35102 Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 

DEPARTMENT OF THE INTERIOR 

30 CFR Parts 1206 and 1210 

[Docket No. ONRR–2014–0001; 

DS63610000; DR2PS0000.CH7000 

145D0102R2] 

RIN 1012–AA15 

Indian Oil Valuation Amendments 

AGENCY: Office of Natural Resources 

Revenue (ONRR), Interior. 

ACTION: Proposed rule. 

SUMMARY: ONRR proposes to amend its 

regulations governing the valuation, for 

royalty purposes, of oil produced from 

Indian leases. The proposed rule would 

clarify the major portion valuation 

requirement found in the existing 

regulations for oil production. The 

proposed rule would represent 

recommendations of the Indian Oil 

Valuation Negotiated Rulemaking 

Committee. This proposed rule also 

contains new reporting requirements to 

implement the changes to the major 

portion valuation requirement. 

DATES: Comments must be submitted on 

or before August 18, 2014. 

ADDRESSES: You may submit comments 

to ONRR on this proposed rulemaking 

by one of the following methods (please 

reference ‘‘1012–AA15’’ in your 

comments): 

D Electronically go to 

www.regulations.gov. In the entry titled 

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

2014–0001,’’ and then click ‘‘Search.’’ 

Follow the instructions to submit public 

comments. ONRR will post all 

comments. 

D Mail comments to Armand 

Southall, Regulatory Specialist, ONRR, 

P.O. Box 25165, MS 61030A, Denver, 

Colorado 80225–0165. 

D 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 

questions on technical issues, contact 

John Barder at (303) 231–3702, Sarah 

Inderbitzin at (303) 231–3082, Karl 

Wunderlich at (303) 231–3663, or 

Elizabeth Dawson at (303) 231–3653, 

ONRR. For comments or questions on 

procedural issues, contact Armand 

Southall, Regulatory Specialist, ONRR, 

telephone (303) 231–3221, or email 

armand.southall@onrr.gov. 

SUPPLEMENTARY INFORMATION: 

I. Background 

The Minerals Revenue Management 

(MRM) program of the Minerals 

Management Service (MMS), now 

ONRR, published the existing rule for 

the major portion provision for the 

valuation of oil produced from Indian 

leases, codified at 30 CFR part 1206, 

subpart B, in the Federal Register on 

January 15, 1988 (53 FR 1184), effective 

March 1, 1988. Since then, many 

changes have occurred in the oil market. 

Also, concerns have arisen about the 

need for revised valuation 

methodologies to address the major 

portion requirement in paragraph 3(c) of 

standard Indian oil and gas leases for 

valuation of oil produced from leases on 

Indian land. 

MRM published proposed rules for 

Indian oil valuation on February 12, 

1998 (63 FR 7089) and on January 5, 

2000 (65 FR 403). MRM subsequently 

withdrew each of these proposed rules 

because of market changes and the 

passage of time. In addition, MRM held 

eight public meetings during 2005 to 

obtain information from, and consult 

with, Indian Tribes and Indian mineral 

owners and other interested parties. 

Then, MRM published a third proposed 

rule on February 13, 2006 (71 FR 7453). 

Tribal and industry commenters on the 

2006 proposed rule did not agree on 

most issues regarding oil valuation, and 

none of the commenters supported the 

major portion provisions. 

Also in 2006, the Royalty Policy 

Committee’s Indian Oil Valuation 

Subcommittee evaluated the proposed 

rule but was unable to reach consensus 

on recommendations to the Department 

of the Interior on how to proceed. Thus, 

MRM decided to make only technical 

amendments to the existing Indian oil 

valuation regulations and convene a 

negotiated rulemaking committee to 

make specific recommendations 

regarding the major portion provision. 

MRM published its final rule addressing 

the technical amendments on December 

17, 2007 (72 FR 71231). The preamble 

of the final rule stated ONRR’s intent to 

convene a negotiated rulemaking 

committee to address the major portion 

valuation requirement for oil produced 

from Indian leases. 

On December 1, 2011, the Secretary of 

the Interior (Secretary) signed the 

charter of the Indian Oil Valuation 

Negotiated Rulemaking Committee 

(Committee). On December 8, 2011, 

ONRR published, in the Federal 

Register, a notice (76 FR 76634) that the 

Department of the Interior established 

and created the Committee authorized 

under the Federal Advisory Committee 

Act. The Secretary established the 

Committee to make recommendations to 

replace existing regulations governing 

the valuation of oil on Indian lands, 

specifically the portion of the 

regulations governing the major portion 

requirement found in most standard 

Indian leases. The Committee met in 

May, June, August, September, and 

October 2012 and in April, June, 

August, and September 2013. 

There were 18 members of the 

Committee. Members of the Committee 

consisted of representatives of Tribes, 

individual Indian mineral owner 

associations, oil companies with 

interests in Indian lands, oil and gas 

trade associations, and the United States 

government. The Shoshone and 

Arapaho Tribes, Land Owners 

Association (Fort Berthold), Navajo 

Nation, Oklahoma Indian Land/Mineral 

Owners of Associated Nations, Ute 

Indian Tribe, Jicarilla Apache Nation, 

and Blackfeet Nation represented Tribes 

and individual Indian mineral owner 

associations. The American Petroleum 

Institute, Council of Petroleum 

Accountants Societies, Western Energy 

Alliance, Chesapeake Energy, Peak 

Energy Resources, and Resolute Energy 

Corporation represented industry. 

ONRR and the Bureau of Indian Affairs 

(BIA) represented the United States 

government. A third-party neutral 

facilitator led all of the meetings, 

coordinated caucuses, provided the 

official minutes, and drafted the final 

report. 

The policy of the Department of the 

Interior (DOI) is, whenever practicable, 

to afford the public an opportunity to 

participate in the rulemaking process. 

ONRR announced all of the Committee 

sessions in the Federal Register. The 

meetings were open to the public to 

provide it the opportunity to participate 

in the rulemaking process. 

ONRR commends the Committee and 

its facilitator for reaching agreement on 

addressing the major portion 

requirement component of the 

regulations governing the value of 

Indian oil. The members’ ability to 

compromise and work together resulted 

in a valuation proposal that would 

assure Indian Tribes and individual 

Indian mineral owners will receive, in 

a timely fashion, royalties based on the 

highest price paid for a major portion of 

production from a field or area. In 

addition, the proposed rule would help 

members of industry avoid significant 

administrative costs and will assure that 

the Department of the Interior meets its 

trust responsibilities to Indian Tribes 

and individual Indian mineral owners. 

II. General Description of the Proposed 

Rule 

In September 2013, the Committee 

published its final report summarizing 

the Committee’s proposal for addressing 

the major portion requirement for 

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Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 35103 

valuing Indian oil production. The 

report forms the basis for this proposed 

rule and is an essential part of the 

history for this proposed rulemaking. 

You can find the report, along with the 

minutes and other supporting materials 

for all meetings at the Committee’s Web 

site at http://www.onrr.gov/Laws_R_D/ 

IONR/. Alternatively, contact Karl 

Wunderlich listed under FOR FURTHER

INFORMATION CONTACT to obtain a mailed 

copy of the report or to answer any 

other questions regarding the Committee 

or this rulemaking. 

ONRR is mandated to establish 

regulations concerning Indian oil 

valuation based on its Federal trust 

responsibility to Indians, including the 

duty to maximize revenue for Indian 

Tribes and Indian mineral owners. As 

such, any action the United States takes 

in relation to Indian-owned trust 

property, including Indian minerals, 

must be that of a trustee who must act 

in a manner that is in the best interest 

of the Indian owner. Keeping in mind 

the responsibility to maximize revenue, 

when faced with more than one 

reasonable alternative, the Secretary 

must choose that alternative that most 

benefits the Indian mineral owner. 

Within the context of the Secretary’s 

Federal trust responsibility, the purpose 

of this rulemaking is to ensure that 

Indian lessors receive maximum 

revenues from their mineral resources. 

In addition, this rule provides 

simplicity, certainty, clarity, and 

consistency for Indian oil production 

valuation for Indian mineral revenue 

recipients and Indian mineral lessees. 

The proposed rule would require a 

lessee to value its oil produced on 

Indian tribal or allotted lands based on 

the higher of (1) the lessee’s gross 

proceeds or (2) an Index-Based Major 

Portion (IBMP) value adjusted by a 

Location and Crude Type Differential 

(LCTD), unique to each designated area 

and crude oil type. The LCTD would 

assure that the calculated major portion 

price represents, on average, the 

equivalent of a 75% major portion price 

calculated by arraying all of the prices 

reported in a designated area from the 

highest to the lowest price and starting 

from the top of the array to determine 

that price associated with the 25th 

percentile by volume plus one barrel of 

oil. ONRR will base the IBMP on the 

calendar month average of prices the 

New York Mercantile Exchange 

(NYMEX) sets, less a differential based 

on the location and crude oil type of the 

oil. Generally, ONRR will base the 

designated areas on reservation 

boundaries, with exceptions, as 

discussed further below. 

Each sales month, ONRR would 

monitor each of the designated areas’ 

reported sales volumes to identify when 

oil sales volumes reported as a lessee’s 

gross proceeds are either more than 28 

percent, or less than 22 percent, of the 

total volumes sold in that designated 

area for the specified crude oil type. In 

months where the volumes in a 

designated area for a particular crude oil 

type fall outside 22 to 28 percent of the 

total volumes sold, ONRR would adjust 

the current month’s LCTD up or down 

by 10 percent. ONRR would then use 

the adjusted LCTD, along with the 

NYMEX Calendar Month Average, to 

calculate the next month’s IBMP value. 

ONRR would continue to adjust the 

LCTD until the percentage of oil sales 

volumes reported as gross proceeds 

reflect between 28 and 22 percent of all 

sales volumes within a designated area 

for the specified crude oil type. ONRR 

would publish the monthly IBMP value 

on its Web site at http://www.onrr.gov. 

In addition, the proposed rule 

modifies some language in the current 

regulations to align with the Federal 

mandate that agencies write all rules in 

plain language. 

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. 

DOI will codify this language in the CFR 

if we finalize the proposed rule as 

written. 

After you have read this proposed 

rule, please return to the preamble 

discussion below. The preamble 

contains additional information about 

this proposed rule, such as why we 

defined a term in a certain manner and 

why we chose a certain method to value 

oil from Indian leases. 

The derivation table below only 

shows a crosswalk of the recodified 

sections of the current and the proposed 

regulations in part 1206, subpart B. 

DERIVATION TABLE FOR PART 1206 

The requirements of section: Are derived 

from section: 

Subpart B 

1206.57 ................................. 1206.57(a) 

1206.58 ................................. 1206.57(b), (f), 

and (g) 

1206.59 ................................. 1206.57(d) 

1206.60 ................................. 1206.57(c) 

and (e) 

1206.61 ................................. 1206.58 

1206.62 ................................. 1206.59 

1206.63 ................................. 1206.60 

DERIVATION TABLE FOR PART 1206— 

Continued 

The requirements of section: Are derived 

from section: 

1206.64 ................................. 1206.61 

1206.65 ................................. 1206.62 

A. Section-by-Section Analysis of 

Proposed Changes to 30 CFR part 

1206—Product Valuation, Subpart B— 

Indian Oil 

ONRR proposes to amend part 1206, 

subpart B, applicable only to Indian oil 

valuation. Many of the provisions are 

the same as in the existing rule in 

substance. However, ONRR rewrote 

some sections for purposes of clarity. 

The main substantive change in the 

proposed rule is proposed at § 1206.54, 

which reflects the Committee’s 

recommendations on how lessees 

should value their oil when their leases 

have a major portion provision or have 

a provision where the Secretary has the 

authority to establish value. 

Purpose (Section 1206.50) 

This section would substantively 

remain the same as current § 1206.50. 

However, we propose to write this 

section in plain language for clarity. 

Definitions (Section 1206.51) 

While ONRR will retain all existing 

definitions, ONRR is adding new terms 

and definitions in this proposed rule to 

support the new IBMP value used in the 

proposed rule at § 1206.54. ONRR 

proposes new definitions for: 

Designated area, Location and Crude 

Type Differential, Major Portion Price, 

Prompt month, Roll, and Trading 

month. ONRR also proposes renaming 

the term NYMEX price to NYMEX 

Calendar Month Average Price and 

revising its definition. Finally, ONRR 

proposes a minor revision to the 

definition Audit to specify that ONRR 

will conduct audits pursuant to the 

Governmental Auditing Standards. 

Designated Area would be defined as 

the area ONRR designates for purposes 

of calculating Location and Crude Type 

Differentials applied to the IBMP value. 

Generally, ONRR would establish 

designated areas by the reservation 

boundaries where location and crude oil 

types are similar to each other. In some 

cases, such as Oklahoma, several fields 

may exist within an area that has similar 

transportation costs and crude oil types. 

In those cases, more than one 

reservation or field may be included 

within a designated area. ONRR would 

post designated areas on its Web site at 

www.onrr.gov. 

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35104 Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 

If there is a significant change that 

affects the differential for a designated 

area, affected Tribes, Indian mineral 

owners, or lessees/operators may 

petition ONRR to consider convening a 

technical committee to review, modify, 

or add designated areas. Criteria to 

determine any future changes include, 

but are not limited to: 

D Markets served, examples include 

refineries and/or market centers, such as 

Cushing, OK; 

D Access to markets, examples 

include, access to similar infrastructure, 

such as pipelines, rail lines, and 

trucking; and/or 

D Similar geography, for example, no 

challenging geographical divides, large 

rivers and/or mountains. 

Initially, ONRR proposes the 

following designated areas: 

1. Fort Berthold—Two designated 

areas: 

D North Fort Berthold—all lands 

within the Fort Berthold Reservation 

boundary north of the Little Missouri 

River, including the Turtle Mountain 

public domain lease lands north of the 

Little Missouri River that the Fort 

Berthold Agency of the BIA administers. 

D South Fort Berthold—all lands 

within the Fort Berthold Reservation 

boundary south of the Little Missouri 

River, including the Turtle Mountain 

public domain lease lands south of the 

Little Missouri River that the Fort 

Berthold Agency of the BIA administers. 

2. Uintah & Ouray—Two designated 

areas: Uintah and Grand Counties; 

Duchesne County. 

3. Oklahoma—One statewide 

designated area encompassing all oil 

production on trust lands, excluding 

Osage County. 

4. Fort Peck—designated area 

includes all lands within the Fort Peck 

Reservation boundary and the Turtle 

Mountain public domain lease lands 

administered by the Fort Peck Agency of 

the BIA. 

5. Fort Belknap—designated area 

includes all lands within the Fort 

Belknap Reservation boundary and the 

Turtle Mountain public domain lease 

lands administered by the Fort Belknap 

Agency of the BIA. 

6. Turtle Mountain—designated area 

includes all lands within the Turtle 

Mountain Reservation and the Turtle 

Mountain public domain lease lands 

administered by the Turtle Mountain 

Agency of the BIA. 

7. The designated area for all other 

reservations would be the reservation 

boundary, including any off-reservation 

allotments or dependent Indian 

communities. They include, but are not 

limited to, the: 

D Blackfeet Indian Reservation. 

D Crow Indian Reservation. 

D Jicarilla Apache Indian Reservation. 

D Isabella Indian Reservation 

(Saginaw Chippewa). 

D Navajo Indian Reservation. 

D Ute Mountain Ute Indian 

Reservation. 

D Wind River Indian Reservation. 

D Alabama/Coushatta Indian 

Reservation. 

D Southern Ute Indian Reservation. 

D Rocky Boy’s Indian Reservation. 

Location and Crude Type Differential 

(LCTD) would mean the difference in 

value between the average of the 

monthly NYMEX Calendar Month 

Average (CMA) for the previous 12 

months and the average of the monthly 

Major Portion Prices for the previous 12 

months for a designated area for any 

given crude oil type. The LCTD also 

captures the difference in value due to 

location and quality differences between 

Light Sweet Crude (WTI) at Cushing, 

Oklahoma and other crude oil types in 

each designated area. 

Initially, ONRR would establish the 

LCTD based on the previous year’s 

average annual difference between the 

NYMEX CMA and the Major Portion 

Price. ONRR would calculate the Major 

Portion Price by arraying all of the 

prices reported in a designated area 

from the highest to the lowest price and 

starting from the top of the array to 

determine that price associated with the 

25th percentile by volume plus one 

barrel of oil. ONRR would calculate a 

separate LCTD for each crude oil type 

within each designated area using all 

calculated values (arm’s-length and nonarm’s-length) payors report on Form 

ONRR–2014. The array to establish the 

initial LCTD also would include sales 

reported on Form ONRR–2014 as 

royalty-in-kind (Transaction Code 06). 

In addition, the sales values ONRR uses 

in the array would be net of 

transportation allowances. 

To calculate the initial LCTD, ONRR 

would require payors to report new 

crude oil types on ONRR Form-2014 

using the existing Product Code field. 

ONRR anticipates having 12 months of 

new reported data to calculate the initial 

LCTD. However, should ONRR not have 

the full 12 months of crude oil types 

prior to the effective date of the rule, 

ONRR would assume the crude oil type 

is the same for those leases/agreements 

for the months for which ONRR does 

have crude oil type data reported on 

Form ONRR–2014s for the same leases 

and/or agreements. 

For leases from which royalty is taken 

in kind now or in the future, ONRR 

would require lessees to report their 

total sales volume and base the sales 

value reported on Form ONRR–2014 on 

the higher of: (1) The IBMP value 

(reported as OINX), or (2) the price the 

lessee receives for volumes sold 

(reported as something other than 

OINX). ONRR would not consider the 

royalty-in-kind share of production in 

determining whether ONRR must 

modify the LCTD for a specific 

designated area and crude oil type. 

Major Portion Price would mean the 

highest price paid or offered at the time 

of production for the major portion of 

oil produced from the same designated 

area for the same crude oil type. 

Prompt month would mean the 

nearest month of delivery for which 

NYMEX futures prices are published 

during the trading month. 

Roll would mean a method for 

adjusting current month prices for 

future prices to smooth the variation in 

oil trading prices and reflect market 

expectations. ONRR proposes to apply a 

‘‘roll’’ to the initial NYMEX oil prices 

from leases in Oklahoma. Because 

NYMEX prices are future price 

estimates, and, therefore, inherently 

reflect increases or decreases in prices 

based upon expected trends, an 

adjustment to such estimates is 

necessary to extrapolate back to current 

price estimates upon which royalty 

calculations are based. This adjustment 

is the ‘‘roll.’’ The roll is added to the 

initial NYMEX price when the market is 

falling (to correct for the fact that the 

current price should be higher than the 

future price in a falling market) and 

subtracted from the initial NYMEX 

prices when the market is rising (to 

correct for the fact that the current price 

should be lower than the future price if 

the market is rising). We propose to use 

the roll because we believe it represents 

current market practice in establishing 

the sales price for crude oil production 

in Oklahoma. 

The roll formula includes the future 

prices for the two months beyond the 

prompt month, which is not the same as 

the prompt month used to determine the 

initial NYMEX price, and assigns a 

progressively smaller weight to the 

second and third months. This is 

consistent with ONRR’s understanding 

of the common industry practice, 

including the weights and basis for the 

prices in the formula below. 

Specifically, the roll would be 

calculated as follows: 

Roll = .6667 × (P0–P1) + .3333 × (P0–P2), 

Where: 

D 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. 

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Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 35105 

D P1 = the average of the daily NYMEX 

settlement prices for deliveries during 

the 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. 

D 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. 

Note that although prices P0, P1, and 

P2 represent separate prices for periods 

1, 2, and 3 months beyond the trading 

month, respectively, they are all 

determined during the same trading 

month. The roll may be a positive or a 

negative number, and, therefore, 

increase or decrease the royalty value, 

depending on whether the futures 

market is falling or rising. For example, 

assume that the month of production for 

which you must determine royalty value 

is March 2013. March was the prompt 

month on the NYMEX from January 23 

through February 20, which is the 

trading month in this case. April is the 

first month following the month of 

production, and May is the second 

month following the month of 

production. As explained above, to 

determine the initial NYMEX price 

which the roll will adjust, for March 

2013 production you first take the 

average of the daily settlement prices 

published for each business day from 

March 1 through March 20 for deliveries 

in April (the prompt month) and for 

each business day from March 21 

through March 31 for deliveries in May 

(after May becomes the prompt month). 

To calculate P0, a different set of days 

is used. P0 is the average of the daily 

NYMEX settlement prices for deliveries 

during March published for each 

business day between January 23 and 

February 20 (the trading month). P1 is 

the average of the daily NYMEX 

settlement prices for deliveries during 

April published for each business day 

during the same trading month, i.e. 

between January 23 and February 20. 

Similarly, P2 is the average of the daily 

NYMEX settlement prices for deliveries 

during May published for each business 

day during the same trading month used 

for P0 and P1. In this example, assume 

that P0 = $98.00 per bbl; P1 = $97.70 per 

bbl; and P2 = $97.10 per bbl. In this 

declining market, the roll = .6667 × 

($98.00 minus 97.70) + .3333 × ($98.00 

minus 97.10) = $0.20 + $0.30 = $0.50. 

Fifty cents per barrel would then be 

added to the initial NYMEX settlement 

price used as the basis for royalty 

valuation. 

In this example, since the market is 

falling, prices that traders anticipate 

during the trading month (March) for 

deliveries in a future prompt month are 

lower than the prices at which oil 

actually is selling during March. The 

roll accounts for that trend. The roll will 

have the opposite effect in a rising 

market. The roll will be a subtraction 

from the initial NYMEX price 

calculation (adding a negative number 

to the NYMEX price) because traders 

anticipate higher prices for the future 

prompt months than actually are 

occurring during the calendar month of 

production. 

The roll would be added to the initial 

NYMEX price used as the basis for 

royalty valuation for Indian leases in 

Oklahoma. This is because sales 

contracts for Indian oil in Oklahoma 

typically include the roll, whereas 

current sales contracts in other 

designated areas do not. 

While ONRR expects the basic 

operation of the NYMEX market to be 

the same for the foreseeable future, it is 

not clear the roll will be a permanent 

feature of the marketplace. Therefore, 

ONRR proposes that the Director of 

ONRR would have the option of 

terminating use of the roll when ONRR 

believes that using the roll is no longer 

a common industry practice. To 

terminate the roll, ONRR will publish a 

notice in the Federal Register. Further, 

ONRR also proposes to have the option 

to redefine how the roll is calculated to 

comport with changes in industry 

practice through a notice published in 

the Federal Register. ONRR will explain 

its rationale when it publishes such 

notice. ONRR believes this flexibility is 

appropriate so the valuation standards 

more closely reflect market 

developments. ONRR specifically 

requests comments on whether these 

options are necessary. 

Trading month would mean 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. 

Royalty Value for Oil I or My Affiliate 

Sells or Exchanges Under an Arm’sLength Contract (Section 1206.52) 

This section is unchanged from the 

existing rule with the exceptions of 

clarifying (1) that value is the higher of 

the value calculated under this section 

or the new major portion provision 

under § 1206.54, (2) that you bear the 

burden of demonstrating that the 

contract is arm’s-length and may be 

required to certify that the contract 

includes all consideration, and (3) that 

this provision applies notwithstanding 

any contrary Code of Federal Regulation 

provisions. Other portions of existing 

§ 1206.52 have been moved to other 

sections of the new regulations. 

Oil Royalty Value Not Sold Under an 

Arm’s-Length Contract (Section 

1206.53) 

This section is unchanged from the 

existing rule with the exception of 

clarifying that value is the higher of the 

value calculated under this section or 

the new major portion provision under 

§ 1206.54. 

Value of Production Based on the Major 

Portion of Like-Quality Oil (Section 

1206.54) 

This section is the principal new 

provision of the proposed regulation 

and is based on the recommendations of 

the Committee. This proposal removes 

the existing text of § 1206.54 and 

replaces it with new language 

explaining how a lessee fulfills the 

obligation under its lease to value crude 

oil produced from Indian leases based 

on the highest prices paid for a major 

portion of production of like-quality oil 

from the field. Proposed paragraph (a) 

states that this would apply to any 

Indian lease that has a major portion 

provision. This section also applies to 

Indian leases where the Secretary of 

Interior may determine value. For such 

leases, paragraph (a) would state that 

the value for royalty purposes is the 

higher of the value determined under 

the section or your gross proceeds under 

§ 1206.52 or § 1206.53. 

Under paragraph (b) of the proposed 

rule, lessees would report royalties on 

the Form ONRR–2014 using the higher 

of (1) an IBMP value, or (2) the lessee’s 

gross proceeds. 

Where the value of the lessee’s oil is 

the gross proceeds accruing to the lessee 

under an arm’s-length contract, the 

lessee would report its gross proceeds 

on its Form ONRR–2014 using Sales 

Type Code (STC) other than OINX. If the 

IBMP value is higher than gross 

proceeds, then the lessee must report 

the IBMP value using STC OINX. If 

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35106 Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 

there is no sale of the crude oil and the 

lessee bases its value on a weighted 

average of the affiliates’ arm’s-length 

purchases and/or sales under § 1206.53, 

then the lessee must report using STC 

NARM. 

Under paragraph (c) of the proposed 

rule, ONRR would calculate the IBMP 

value using the NYMEX CMA 

(excluding weekends and holidays) for 

each designated area less the LCTD. As 

explained above, the LCTD is based on 

the average difference between the 

NYMEX CMA and the major portion 

price at the 25th percentile by volume 

plus one barrel from highest price to 

lowest price, starting from the top (the 

top means that volume associated with 

the highest price for any given month). 

For leases in Oklahoma, the IBMP value 

would include the ‘‘roll,’’ as defined 

above. 

The IBMP value would be calculated 

as follows: 

Paragraph (d) describes how ONRR 

would calculate the LCTD for each 

designated area. As explained above, 

LCTD captures the difference in value 

due to location and quality differences 

between Light Sweet Crude (WTI) at 

Cushing, Oklahoma and other crude oil 

types in each designated area. The 

LCTD also ensures that the IBMP price 

closely reflects the 75% major portion 

value of a particular crude type within 

the applicable designated area. 

Paragraph (d) provides details on how 

ONRR would calculate the LCTD for 

each designated area. Initially, ONRR 

would establish the LCTD based on the 

previous year’s average annual 

difference between the NYMEX CMA 

and the Major Portion Price calculated 

by arraying all of the prices reported in 

a designated area from the highest to the 

lowest price and starting from the top of 

the array, determining that price 

associated with the 25th percentile by 

volume plus one barrel of oil. Paragraph 

(1) would explain that ONRR would 

calculate a separate LCTD for each 

crude type within each designated area 

using all data (arm’s-length and nonarm’s-length) payors report on Form 

ONRR–2014 for the previous 12 

production months prior to the effective 

date of the rule. If ONRR does not have 

12 months of data prior to the effective 

date of the rule, then it would assume 

the data is the same as that for the 

months for which data was reported. 

ONRR would apply this initial LCTD 

the first month after the effective date of 

the rule. 

As an example, assume that for the 

initial LCTD for a specific designated 

area and crude type, ONRR calculated a 

prior year average annual major portion 

value of $81.54. Further, assume that 

ONRR calculated a prior year average 

annual NYMEX CMA of $95.12. Then 

assume that the effective date of the rule 

is March 30, 2015. Lastly, assume the 

NYMEX CMA for April 2015 is $94.56. 

ONRR would calculate the LCTD for 

Designated Area X as follows: 

ONRR would then apply the initial 

LCTD to the April 2015 NYMEX CMA 

to calculate the IBMP value as follows: 

$94.56 × (1 ¥ 0.1428) = $81.06 

If your gross proceeds value is more 

than the $81.06 IBMP value, you would 

have to report your gross proceeds on 

Form ONRR–2014 using the appropriate 

STC other than OINX, such as ARMS. If 

your gross proceeds value is less than 

the $81.06 IBMP value, then you would 

have to report the IBMP value using 

STC OINX. 

Paragraph (d)(2) of the proposed rule 

outlines how ONRR would monitor the 

LCTD after its initial calculation. ONRR 

would monitor each of the designated 

areas’ monthly sales volumes lessees 

report on their Form ONRR–2014s to 

identify when oil sales volumes not 

reported as STC OINX are either more 

than 28 percent or less than 22 percent 

of the total sales volumes reported in 

that designated area for a specific crude 

oil type. When sales volumes not 

reported as OINX for a specific crude oil 

type in a designated area exceed 28 

percent or fall below 22 percent of the 

total volumes sold, ONRR would adjust 

the next month’s LCTD down or up by 

10 percent of the current month’s LCTD. 

ONRR would then use the adjusted 

LCTD, along with the NYMEX CMA to 

calculate the next month’s IBMP value. 

ONRR would continue to adjust the 

LCTD each month until the percentage 

of oil sales volumes not reported as 

OINX reflects between 28 and 22 

percent of all sales volumes within a 

designated area for the specified crude 

oil type. ONRR would publish the 

monthly IBMP value on its Web site at 

http://www.onrr.gov. The proposed rule 

provides two examples demonstrating 

how the trigger for the LCTD works. 

Paragraph (e) provides that ONRR 

would use its discretion to determine an 

appropriate IBMP value where there are 

insufficient royalty lines reported to 

ONRR on Form ONRR–2014 to 

determine a differential for a specific 

crude oil type. For example, there will 

be some instances, including, but not 

limited to, sales of condensate, where it 

is impossible for ONRR to calculate an 

appropriate differential. In those 

circumstances, ONRR would determine 

the IBMP value. ONRR is concerned that 

if an LCTD were to vary to a significant 

degree, for example +/¥20 percent, it 

could take ONRR numerous months to 

bring the LCTD back to within +/¥3 

percent of the 25 percent of total oil 

sales volumes reported in a designated 

area for a specific crude oil type. 

Therefore, we specifically request 

comments on whether ONRR should 

modify paragraph (e) to provide that 

ONRR would use its discretion to 

determine an appropriate IBMP value 

where there are insufficient lines 

reported to ONRR on Form ONRR–2014 

to determine a differential for a specific 

crude oil type or when the LCTD varies 

more than +/¥20 percent. We also 

request comments on what could 

constitute a significant variation. 

Responsibility To Place Production Into 

Marketable Condition and Market 

Production (Section 1206.55) 

This section would remain the same 

as current § 1206.55. However, we 

propose to divide this section into two 

subsections, (a) and (b), and to write this 

section in plain language for clarity. 

General Transportation Allowance 

Requirements (Section 1206.56) 

This section would remain the same 

as current § 1206.56 except for adding 

language from (1) the current 

§ 1206.57(a) stating that transportation 

allowances are subject to monitoring, 

review, adjustment, and audit and (2) 


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the current § 1206.51 and § 1206.52 

stating that you may not deduct 

gathering costs as transportation 

allowances or deductions. In addition, 

we propose to rewrite this section and 

its section name in plain language to 

provide clarity. 

Arm’s-Length Contract Transportation 

Allowances (Section 1206.57); NonArm’s-Length Contract or No Contract 

Transportation Allowances (Section 

1206.58); Late Payment Interest for 

Improper Transportation Allowance 

Reporting (Section 1206.59); Reporting 

Adjustments for Transportation 

Allowances (Section 1206.60) 

ONRR would reorganize § 1206.57 

into proposed new §§ 1206.57, 1206.58, 

1206.59, and 1206.60. Proposed 

§ 1206.57 would govern how to 

determine and report transportation 

allowances if there is an arm’s-length 

transportation contract, currently in 

§ 1206.57(a) and (c)(1). Proposed 

§ 1206.58 would govern how to 

determine and report transportation 

allowances under non-arm’s-length 

transportation contracts, which is 

currently in § 1206.57(b) and (c)(2). 

Section 1206.58 also includes existing 

paragraphs (f) and (g) of § 1206.57 as 

proposed § 1206.58(c) and (d). ONRR 

proposes to add § 1206.59 to show how 

ONRR would calculate interest where a 

lessee improperly reports a 

transportation allowance. Currently, 

interest assessments for transportation 

allowances can be found in 

§ 1206.57(d). ONRR proposes to move 

the current provision in § 1206.57(e)— 

adjusting transportation allowances— 

under proposed § 1206.60. 

ONRR Determination of Correct Royalty 

Payments (Section 1206.61) 

Because of the changes in the 

proposed rule regarding transportation 

allowances, the proposed rule 

redesignates § 1206.58 as § 1206.61. In 

the proposed rule, the provisions are the 

same as in the existing rule in § 1206.58 

in substance but clarify how ONRR will 

determine if royalty payments are 

correct and what to do when royalty 

payments are incorrect. 

Valuation Determination Requests 

(Section 1206.62) 

Because of the changes in the 

proposed rule regarding transportation 

allowances, the proposed rule 

redesignates § 1206.59 as § 1206.62. 

This new section is the same as in the 

existing rule in substance in 1206.59. 

However, the proposed rule provides 

clarity by expanding how to request a 

valuation determination and how ONRR 

responds to such requests. 

Determination of Royalty Quantity and 

Quality (Section 1206.63) 

Because of the changes in the 

proposed rule regarding transportation 

allowances, the proposed rule 

redesignates § 1206.60 as § 1206.63. The 

provisions are the same as in the 

existing § 1206.60. 

Recordkeeping Requirements (Section 

1206.64) 

This proposed section is the same as 

current § 1206.61. However, we propose 

to write this section in plain language 

for clarity. 

ONRR’s Protection of Information 

Submitted (Section 1206.65) 

This proposed section is the same as 

current § 1206.62. However, we propose 

to divide this section into three 

subsections, (a), (b), and (c), and to write 

in plain language for clarity. 

B. Section-by-Section Analysis of 

Proposed Changes to 30 CFR Part 

1210—Forms and Reports, Subpart B— 

Royalty Reports—Oil, Gas, and 

Geothermal Resources 

ONRR proposes to amend Part 1210 

by adding § 1210.61 that contains 

additional reporting requirements for 

crude oil. The new proposed 

§ 1210.61(a) requires payors to report 

Sales Type Code ARMS on their Form 

ONRR–2014 when valuing oil under 

§ 1206.52. The new proposed 

§ 1210.61(b) requires payors to report 

Sales Type Code NARMS on their Form 

ONRR–2014 when valuing oil under 

§ 1206.53. The new proposed 

§ 1210.61(c) requires payors to report 

Sales Type Code OINX on their Form 

ONRR–2014 when valuing oil under 

§ 1206.54. Under § 1210.61(d), crude oil 

type payors would report five crude oil 

types: (1) Sweet as product code 61; (2) 

sour as product code 62; (3) asphaltic as 

product code 63; (4) black wax as 

product code 64; and (5) yellow wax as 

product code 65. 

Before the effective date of the rule, 

ONRR would explain that payors should 

report using the additional product 

codes reflecting the crude oil type of the 

Indian oil within a particular designated 

area on the payors’ Form ONRR–2014s. 

Prior to the effective date of the rule, 

ONRR would issue a letter to all payors 

explaining when to begin reporting such 

product codes and how to report the 

crude oil types. 

IV. Other Possible Changes ONRR May 

Consider 

A. Transportation Allowances—Form 

Filing 

For arm’s-length transportation 

agreements, ONRR would like 

comments on removing the requirement 

under the current rule to file a Form 

ONRR–4110, Oil Transportation 

Allowance Report. Instead, the lessee 

would have to submit to ONRR copies 

of its arm’s-length transportation 

contract(s) and any amendments thereto 

within 2 months after the lessee 

reported a transportation allowance on 

its Form ONRR–2014. This change 

would mirror the requirement to file 

arm’s-length transportation contracts 

with ONRR, instead of a form, under the 

current Indian Gas Valuation Rule at 

§ 1206.178(a)(1)(i). 

For non-arm’s-length transportation 

arrangements, ONRR would like 

comments on eliminating the 

requirement that lessees submit a Form 

ONRR–4110 in advance with estimated 

information. Lessees would still be 

required to submit the Form ONRR– 

4110. However, the lessee would submit 

actual cost information in support of the 

allowance on its Form ONRR–4110 

within 3 months after the end of the 12- 

month period to which the allowance 

applies. This change would also mirror 

the 1999 Indian Gas Rule. 

Of note, under the proposed rule, 

there would be no form filing 

requirements where a lessee values its 

oil under the IBMP value (proposed rule 

§ 1206.54). Thus, these changes to the 

form filing requirements would only 

apply to those lessees reporting their oil 

royalties as either gross proceeds under 

§ 1206.52 or as non-arm’s-length under 

§ 1206.53. 

As ONRR explained when it proposed 

these changes in the 1999 Indian Gas 

Rule, ONRR believes these changes 

‘‘would ease the burden on industry and 

still provide ONRR with documents 

useful to verify the allowance claimed.’’ 

ONRR requests comments on (1) 

eliminating the form filing requirement 

for arm’s-length contracts and instead 

submitting the contract(s) to ONRR; and 

(2) removing the current rule’s 

requirement that lessees reporting nonarm’s-length transportation 

arrangements submit a Form ONRR– 

2014 with estimated information prior 

to taking the transportation allowance. 

B. Transportation Factors 

ONRR requests comments on 

eliminating transportation factors from 

the regulations. Currently, 

§ 1206.57(a)(5) allows lessees to reduce 

their gross proceeds where their arm’smstockstill on DSK4VPTVN1PROD with PROPOSALS

35108 Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 

length transportation contract includes a 

provision reducing the applicable price 

by a transportation factor. Under the 

current rule, lessees report their gross 

proceeds net of the transportation factor 

on their Form ONRR–2014s. Thus, 

unlike the transportation allowances, 

which lessees report on their Form 

ONRR–2014s, ONRR cannot tell if 

lessees are taking a deduction for 

transportation when lessees report their 

gross proceeds net of a transportation 

factor. As such, the reporting 

requirements for transportation factors 

are not transparent. Eliminating the 

ability to net an arm’s-length 

transportation fee would require lessees 

to report these transportation fees as a 

transportation allowance. ONRR 

specifically requests comments on 

whether to eliminate transportation 

factors completely, which would require 

reporting of the arm’s-length 

transportation as a transportation 

allowance on Form ONRR–2014. 

C. Limiting Allowances 

ONRR is also considering removing 

the exception to the 50-percent 

limitation on transportation allowances. 

Under the current rule at 

§ 1206.56(b)(2), a lessee may request an 

exception to the rule that transportation 

allowances cannot exceed 50 percent of 

the value of the oil at the point of sale. 

ONRR seeks input on whether it would 

be a better exercise of the Secretary’s 

trust responsibility to not allow cost 

allowances for transporting production 

from Indian leases to exceed 50 percent 

of the value of the oil. To date, ONRR 

has not received any requests to exceed 

the 50-percent limitation for 

transportation allowances. ONRR 

specifically requests comments on 

removing any exceptions to the 50- 

percent limitation on transportation 

allowances, under § 1206.56(b)(1). 

V. Procedural Matters 

1. Summary Cost and Royalty Impact 

Data 

We estimated the costs and benefits 

that this rulemaking may have on all 

potentially affected groups: Industry, 

Indian Lessors, and the Federal 

Government. The proposed amendment 

would result in an estimated annual 

increase in royalty collections of 

between $19.4 million and $20.6 

million to be disbursed to Indian 

lessors. This net impact represents a 

minimal increase of between 3.82 

percent and 3.93 percent of the total 

Indian oil royalties ONRR collected in 

2012. We also estimate that Industry 

and the Federal Government would 

experience one-time increased system 

costs of approximately $ 4.84 million 

and $247 thousand, respectively. 

A. Industry 

The table below lists ONRR’s low, 

mid-range, and high estimates of the 

costs that Industry would incur in the 

first year (excluding one-time system 

costs). Industry would incur these costs 

in the same amount each year thereafter. 

SUMMARY OF ROYALTY IMPACTS TO

INDUSTRY

Low Mid High 

$19,400,000 $20,000,000 $20,600,000 

Cost—Using the Higher of the IndexBased Major Portion Formula Value or 

Gross Proceeds to Value Indian Oil 

Sales 

As discussed above, we propose to 

add a provision under 30 CFR 1206.54 

that explains how a lessee must meet its 

obligation to value oil produced from 

Indian leases based on the highest price 

paid for a major portion of like-quality 

oil from the field. The proposed rule 

defines the monthly IBMP value that 

lessee must compare to its gross 

proceeds and pay on the higher of those 

two values. 

To perform this economic analysis, 

ONRR used royalty data we collected for 

Indian oil (product code 01) for calendar 

year 2012. We chose calendar year 2012 

because most data reported has gone 

through ONRR edits and lessees have 

made most of their adjustments. We did 

not distinguish crude oil type within 

each designated area because (1) based 

on our experience, crude oil type within 

each designated area is generally the 

same and (2) lessees currently do not 

report crude oil type to ONRR. 

We then segregated the data into the 

following 14 Designated Areas: 

1. Uintah & Ouray—Uintah and Grand 

Counties. 

2. Uintah & Ouray—Duchesne 

County. 

3. North Fort Berthold. 

4. South Fort Berthold. 

5. Oklahoma—One statewide area 

excluding Osage County. 

6. Fort Peck. 

7. Turtle Mountain. 

8. Blackfeet Indian Reservation. 

9. Crow Indian Reservation. 

10. Jicarilla Apache Indian 

Reservation. 

11. Isabella Indian Reservation 

(Saginaw Chippewa). 

12. Navajo Indian Reservation. 

13. Ute Mountain Ute Indian 

Reservation. 

14. Wind River Indian Reservation. 

We first arrayed the monthly reported 

prices net of transportation from highest 

to lowest and then calculated the 

monthly major portion price as that 

price at which 25 percent plus 1 barrel 

(by volume) of the oil is sold (starting 

from the highest price). Next, we 

calculated the difference between the 

reported prices and the major portion 

price. For any price below the major 

portion price, we multiplied the price 

difference by the royalty volume to 

estimate additional royalties. 

Last, we totaled all of the monthly 

additional royalties for each designated 

area and then totaled all of the areas to 

arrive at an additional average royalty 

amount of $20 million. This represents 

3.70 percent of all Indian oil royalties 

collected in 2012 or approximately 

$0.558/bbl. 

Of note, we did not use the LCTD in 

this analysis. The LCTD is used in the 

IBMP value to keep the gross proceeds 

volume near the 25th percentile, 

through monthly monitoring and 

adjustments to the LCTD. Rather, we 

used the actual monthly major portion 

price in our analysis. Because we used 

the actual monthly major portion price, 

we did not account for the potential 

+/¥3 percent volume variation 

adjustments the rule would allow. 

Instead, we created a 

+/¥3 percent range of royalty impacts 

above and below the estimated 

additional royalties, reflected in the 

table above. 

Cost—System Changes To 

Accommodate Reporting of Crude Oil 

Type 

ONRR needs to know crude oil types 

to calculate and publish the IBMP value. 

Therefore, proposed § 1210.61 requires a 

lessee to report crude oil types using 

new product codes on the Form ONRR– 

2014. ONRR anticipates a lessee would 

need to make computer system changes 

to add these new product codes to their 

automated reporting. 

We identified 205 Indian payors 

(those reporting and paying royalties to 

ONRR) in 2012. Of those, ONRR 

identified 32 as large businesses and 

173 as small businesses (based on the 

SBA definition of a small business 

having 500 employees or less). To more 

accurately reflect the Indian payor 

community based on our experience, we 

reclassified the 173 small businesses 

into two categories—medium and small 

companies. We defined a medium 

company as those companies with 

between 250 and 500 employees. We 

also defined small companies as those 

companies with 250 or less employees. 

We classified 58 companies as medium 

companies and 115 companies as small 

companies. 

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Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 35109 

ONRR first identified the changes we 

must make to our systems to 

accommodate the requirements (adding 

product codes and edits, changing and 

adding reports, and modifying Oil and 

Gas Operations Reports, Form ONRR– 

4054 (OGORs)) of this proposed rule 

and then estimated the number of hours 

needed to make those changes. We then 

multiplied those hours by our estimated 

hourly cost (including contractors) to 

implement system changes. Some of the 

hours calculated for ONRR include costs 

Industry would not incur, such as 

eCommerce updates, changes to the 

compliance management tool, and web 

publishing. 

We used this same process for large 

businesses, reducing or eliminating the 

hours for some categories but used the 

same hourly cost because most large 

companies employ system contractors 

similar to those ONRR employs, and, 

therefore, would have similar system 

change costs. 

We reduced the hours for the medium 

(200 hours) and small companies (100 

hours) to reflect the fact that their 

systems are smaller and less complex. 

We also reduced the hourly rate for 

medium and small businesses to $100 

and $75, respectively, reflecting lower 

contractor costs. The table below 

provides our estimate of system change 

costs for both ONRR and Industry. 

System changes ONRR Large 

business 

Medium 

business 

Small 

business 

Adding product codes to ONRR 2014–PS ...................................................... 100 100 100 50 

Adding product codes to ONRR 2014–eCommerce ....................................... 100 0 0 0 

Adding new edit ............................................................................................... 150 75 0 0 

Changing reports ............................................................................................. 250 100 0 0 

Changes to CPT .............................................................................................. 150 0 0 0 

Changes to Web publishing ............................................................................ 150 0 0 0 

Changes to OGOR/PASR form ....................................................................... 150 100 100 50 

Total hours ................................................................................................ 1,050 375 200 100 

Average hourly rate ......................................................................................... × $235 × $235 × $100 × $75 

Cost per entity .................................................................................................

[Total hours × Average hourly rate] ................................................................. $246,750 $88,125 $20,000 $7,500 

Number of Businesses .................................................................................... N/A × 32 × 58 × 115 

Total cost .................................................................................................. ........................ $2,820,000 $1,160,000 $862,500 

Industry Grand Total ......................................................................... ........................ ........................ ........................ $4,842,500 

The table below lists the overall 

estimated first year economic impact to 

industry from the proposed changes, 

based on the mid-range estimate of 

costs: 

Description 

Annual 

(cost)/benefit 

amount 

Cost—Major Portion ......... ($20,000,000) 

Cost—System Changes ... ($4,842,500) 

Net First Year Cost to 

Industry ...................... ($24,842,500) 

After the first year, we anticipate the 

estimated cost to Industry to be 

approximately $20,000,000 each year, 

based on 2012 data. 

B. Indian Lessors 

The impact to Indian Lessors would 

be a net overall increase in royalties as 

a result of this proposed change. This 

royalty increase would equal the royalty 

increase from Industry, or $20 million. 

C. Federal Government 

Cost—System Changes To 

Accommodate Reporting of Crude Oil 

Type 

The Federal Government would incur 

system costs to accommodate crude oil 

type reporting similar to Industry. As 

detailed above, ONRR estimates that it 

would take 1,050 hours to implement 

system changes related to the proposed 

rule equating to a total cost of $246,750. 

This rulemaking would have no 

impact on Federal royalties. We also 

believe that there would be no 

administrative cost increases to the 

Federal Government because the 

additional work needed to monitor and 

adjust the LCTD and IBMP value would 

be offset by administrative savings due 

to decreased audit and litigation costs. 

D. Summary of Royalty Impacts and 

Costs to Industry, Indian Lessors, and 

the Federal Government 

In the table below, the negative values 

in the Industry column represent their 

estimated royalty and cost increases, 

while the positive values in the other 

columns represent the increase in 

Indian royalty receipts. For purposes of 

this summary table, we assumed that 

the average for royalty increases is the 

midpoint of our range. 

SUMMARY OF COSTS & ROYALTIES THE FIRST YEAR

Industry Indian Federal 

Government 

Annual Additional Royalties Paid .............................................................................. ($20,000,000) $0 $0 

Cost to Modify Systems ............................................................................................. ($4,842,500) $0 ($246,750) 

Additional Royalties Received ................................................................................... $0 $20,000,000 $0 

Total .................................................................................................................... ($24,842,500) $20,000,000 ($246,750) 

After the first year, the proposed rule 

will cost industry approximately $20 

million a year and Indian lessors will 

increase their annual royalty receipts by 

approximately $20 million. The Federal 

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35110 Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 

Government will not incur any 

additional costs after the first year. 

2. Regulatory Planning and Review 

(Executive Orders 12866 and 13563) 

Executive Order (E.O.) 12866 provides 

that the Office of Information and 

Regulatory Affairs (OIRA) of the Office 

of Management and Budget (OMB) will 

review all significant rulemaking. OIRA 

has determined that this proposed rule 

is not significant. 

Executive Order 13563 reaffirms the 

principles of E.O. 12866 while calling 

for improvements in the nation’s 

regulatory system to promote 

predictability, to reduce uncertainty, 

and to use the best, most innovative, 

and least burdensome tools for 

achieving regulatory ends. The 

executive order directs agencies to 

consider regulatory approaches that 

reduce burdens and maintain flexibility 

and freedom of choice for the public 

where these approaches are relevant, 

feasible, and consistent with regulatory 

objectives. E.O. 13563 emphasizes 

further that regulations must be based 

on the best available science and that 

the rulemaking process must allow for 

public participation and an open 

exchange of ideas. We have developed 

this proposed rule in a manner 

consistent with these requirements. 

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.). Lessees of Federal 

and Indian mineral leases are generally 

companies classified under the North 

American Industry Classification 

System (NAICS) Code 211111, which 

includes companies that extract crude 

petroleum and natural gas. For this 

NAICS code classification, a small 

company is one with fewer than 500 

employees. Approximately 205 different 

companies submit royalty and 

production reports from Indian leases to 

ONRR each month. In addition, 

approximately 32 companies are large 

businesses under the U.S. Small 

Business Administration definition 

because they have over 500 employees. 

The remaining 173 companies are 

considered to be small business. 

As provided in 1A Industry in the 

Procedural Matters section, we believe 

industry would incur a one-time cost to 

comply with the proposed rule. On 

average, ONRR estimates that each small 

business would incur a one-time cost of 

between of $7,500 and $20,000 to 

modify their systems to comply with 

this rulemaking. 

As we stated earlier, we believe, based 

on 2012 Indian oil sales, the proposed 

rule would cost industry approximately 

$20 million dollars a year. Small 

businesses only accounted for 13.55 

percent of the oil volumes sold in 2012. 

Applying that percentage to industry 

costs, ONRR estimates that the proposed 

major portion provision would cost all 

small-business lessors approximately 

$2,710,000 per year. The amount would 

vary for each company depending on 

the volume of production each small 

business produces and sells each year. 

We believe reduced administrative 

costs, such as reduced accounting, 

auditing, and litigation expenses, would 

offset some of these costs. 

In sum, we do not believe this 

rulemaking would result in a significant 

economic effect on a substantial number 

of small entities because (1) the initial 

one-time cost to a small business to 

modify its system would be between 

$7,500 and $20,000; and (2) this 

proposed rule would cost the small 

businesses a collective total of 

$2,710,000 per year. 

ONRR encourages small businesses to 

comment on this proposed rule. 

4. Small Business Regulatory 

Enforcement Fairness Act (SBREFA) 

This proposed rule would not be a 

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

Small Business Regulatory Enforcement 

Fairness Act. This rulemaking: 

a. Would not have an annual effect on 

the economy of $100 million or more. 

The effect would be limited to a 

maximum estimated at $2,710,000 

which equals the $20,000,000 yearly 

cost of the proposed rule to industry at 

large multiplied by 13.55% (volumes 

sold attributable to small businesses). 

b. Would not cause a major increase 

in costs or prices for consumers, 

individual industries, Federal, State, 

Indian, or local government agencies, or 

geographic regions. 

c. Would not have significant adverse 

effects on competition, employment, 

investment, productivity, innovation, or 

the ability of United States-based 

enterprises to compete with foreignbased enterprises. 

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 

rulemaking would not have a significant 

or unique effect on State, local, or Tribal 

governments or the private sector. A 

statement containing the information 

required by the Unfunded Mandates 

Reform Act (2 U.S.C. 1501 et seq.) 

would not be required. 

6. Takings (E.O. 12630) 

Under the criteria in section 2 of E.O. 

12630, this proposed rule would not 

have any significant takings 

implications. This proposed rule would 

not impose conditions or limitations on 

the use of any private property. 

Therefore, a takings implication 

assessment is not required. 

7. Federalism (E.O. 13132) 

Under the criteria in section 1 of E.O. 

13132, this proposed rule would not 

have sufficient federalism implications 

to warrant the preparation of a 

Federalism summary impact statement. 

This rulemaking would not 

substantially and directly affect the 

relationship between the Federal and 

State governments. The management of 

Indian leases is the responsibility of the 

Secretary of the Interior, and all 

royalties ONRR collects from Indian 

leases are distributed to Tribes and 

individual Indian mineral owners. 

Because this proposed rule would not 

alter that relationship, a Federalism 

summary impact statement is not 

required. 

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

This rulemaking would comply with 

the requirements of E.O. 12988. 

Specifically, this proposed rule: 

a. Would meet the criteria of section 

3(a) requiring that all regulations be 

reviewed to eliminate errors and 

ambiguity and be written to minimize 

litigation. 

b. Would meet the criteria of section 

3(b)(2) requiring that all regulations be 

written in clear language and contain 

clear legal standards. 

9. Consultation With Indian Tribal 

Governments, (E.O. 13175) 

The Department of the Interior strives 

to strengthen its government-togovernment relationship with Indian 

Tribes through a commitment to 

consultation with Indian Tribes and 

recognition of their right to selfgovernance and Tribal sovereignty. 

Under the Department’s consultation 

policy and the criteria in E.O. 13175, we 

evaluated this proposed rule and 

determined that it would have no tribal 

implications that would impose 

substantial direct compliance costs on 

Indian tribal governments. Also, under 

this consultation policy and Executive 

Order criteria with Indian tribes and 

individual Indian mineral owners on all 

policy changes that may affect them, 

ONRR scheduled public meetings in 

three different locations for the purpose 

of consulting with Indian tribes and 

individual Indian mineral owners and 

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Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 35111 

to obtain public comments from other 

interested parties. 

ONRR held consultation sessions with 

Tribes and individual Indian mineral 

owners on October 29, 2013, at the Civic 

Center in New Town, North Dakota; 

November 6, 2013, at Ft. Washakie, 

Wyoming; and December 14, 2013, at 

the Wes Watkins Technology Center at 

Wetumka, Oklahoma. ONRR plans to 

schedule additional consultation 

sessions with Tribes and individual 

Indian mineral owners to discuss and 

hear comments, including sessions in 

Albuquerque, New Mexico; Browning, 

Montana; and Ft. Duchesne, Utah. 

10. Paperwork Reduction Act of 1995 

This rulemaking would not contain 

new information collection 

requirements, and a submission to the 

Office of Management and Budget 

(OMB) would not be required under the 

Paperwork Reduction Act of 1995 (44 

U.S.C. 3501 et seq.). The proposed rule 

would modify § 1210.61 to require a 

lessee of Indian leases to report 

additional product codes for crude oil 

types on Form ONRR–2014. Currently, 

OMB approved a total of 239,937 

burden hours for lessees to file their 

Form ONRR–2014s under OMB Control 

Number 1012–0004. ONRR estimates no 

additional burden hours, beyond the 

initial hours that industry must incur to 

modify systems to accommodate the 

rule, to report the applicable crude oil 

type in the product code field. 

11. National Environmental Policy Act 

This proposed rule would not 

constitute a major Federal action 

significantly affecting the quality of the 

human environment. We are not 

required to provide a detailed statement 

under the National Environmental 

Policy Act of 1969 (NEPA) because this 

proposed rule qualifies for categorical 

exclusion under 43 CFR 46.210(c) and 

(i) and the DOI Departmental Manual, 

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

financial transactions including such 

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

royalties . . . (i) Policies, directives, 

regulations, and guidelines: that are of 

an administrative, financial, legal, 

technical, or procedural nature.’’ We 

have also determined that this 

rulemaking 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 the IBMP value 

would have no consequence on the 

physical environment. This proposed 

rule would not alter, in any material 

way, natural resources exploration, 

production, or transportation. 

12. Effects on the Nation’s Energy 

Supply (E.O. 13211) 

This rulemaking would not be a 

significant energy action under the 

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

would not require a Statement of Energy 

Effects. 

13. Clarity of This Regulation 

We are required by E.O. 12866 

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

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

and Presidential Memorandum of June 

1, 1998, to write all rulemaking in plain 

language. This means that each 

rulemaking we publish must: (a) Be 

logically organized; (b) use the active 

voice to address readers directly; (c) use 

common, everyday words, and clear 

language rather than jargon; (d) be 

divided into short sections and 

sentences; and (e) use lists and tables 

wherever possible. 

If you feel that we have not met these 

requirements, send us comments by one 

of the methods listed in the ADDRESSES

section. To help revise the proposed 

rule, write your comments as specific as 

possible. For example, you should tell 

us the numbers of the sections or 

paragraphs that you find unclear, which 

sections or sentences are too long, and 

the sections where you feel lists or 

tables would be useful, etc. 

14. Public Availability of Comments 

We will post all comments, including 

names and addresses of respondents, at 

www.regulations.gov. Before including 

Personally Identifiable Information (PII), 

such as address, phone number, email 

address, or other personal information 

in your comment(s), be advised that 

your entire comment (including PII) 

may be made available to the public at 

any time. While you can ask us, in your 

comment, to withhold PII from public 

view, we cannot guarantee that we will 

be able to do so. 

List of Subjects in 30 CFR Parts 1206 

and 1210 

30 CFR Parts 1206 

Coal, Continental shelf, Geothermal 

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

exploration, Public lands—mineral 

resources, Reporting and recordkeeping 

requirements. 

30 CFR Part 1210 

Continental shelf, Indian leases, 

Geothermal energy, Government 

contracts, Indians-lands, Mineral 

royalties, Oil and gas reporting, 

Phosphate, Potassium, Reporting and 

recordkeeping requirements, Royalties, 

Sales contracts, Sales summary, 

Sodium, Solid minerals, Sulfur. 

Dated: May 13, 2014. 

Rhea Suh, 

Assistant Secretary for Policy, Management 

and Budget. 

Authority and Issuance 

For the reasons discussed in the 

preamble, ONRR proposes to amend 30 

CFR parts 1206 and 1210 as follows: 

PART 1206—PRODUCT VALUATION 

■ 1. The authority 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. 

■ 2. Revise subpart B of part 1206 to 

read as follows: 

Subpart B—Indian Oil 

Sec. 

1206.50 What is the purpose of this 

subpart? 

1206.51 What definitions apply to this 

subpart? 

1206.52 How do I calculate royalty value 

for oil that I or my affiliate sell(s) or 

exchange(s) under an arm’s-length 

contract? 

1206.53 How do I calculate royalty value 

for oil that I or my affiliate do(es) not sell 

under an arm’s-length contract? 

1206.54 How do I fulfill the lease provision 

regarding valuing production on the 

basis of the major portion of like-quality 

oil? 

1206.55 What are my responsibilities to 

place production into marketable 

condition and to market production? 

1206.56 What general transportation 

allowance requirements apply to me? 

1206.57 How do I determine a 

transportation allowance if I have an 

arm’s-length transportation contract? 

1206.58 How do I determine a 

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

have no contract? 

1206.59 What interest applies if I 

improperly report a transportation 

allowance? 

1206.60 What reporting adjustments must I 

make for transportation allowances? 

1206.61 How will ONRR determine if my 

royalty payments are correct? 

1206.62 How do I request a value 

determination? 

1206.63 How do I determine royalty 

quantity and quality? 

1206.64 What records must I keep to 

support my calculations of value under 

this subpart? 

1206.65 Does ONRR protect information I 

provide? 

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35112 Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 

Subpart B—Indian Oil 

§ 1206.50 What is the purpose of this 

subpart? 

(a) This subpart applies to all oil 

produced from Indian (tribal and 

allotted) oil and gas leases (except leases 

on the Osage Indian Reservation, Osage 

County, Oklahoma). This subpart does 

not apply to Federal leases, including 

Federal leases for which revenues are 

shared with Alaska Native Corporations. 

This subpart: 

(1) Explains how you as a lessee must 

calculate the value of production for 

royalty purposes consistent with Indian 

mineral leasing laws, other applicable 

laws, and lease terms. 

(2) Ensures the United States 

discharges its trust responsibilities for 

administering Indian oil and gas leases 

under the governing Indian mineral 

leasing laws, treaties, and lease terms. 

(b) If you dispose of or report 

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 the regulations in this subpart 

are inconsistent with: 

(1) A Federal statute; 

(2) A settlement agreement between 

the United States, Indian lessor, and a 

lessee resulting from administrative or 

judicial litigation; 

(3) A written agreement between the 

Indian lessor, 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 or Indian Tribes, which 

have a cooperative agreement with 

ONRR to audit under 30 U.S.C. 1732, 

may audit, or perform other compliance 

reviews, and require a lessee to adjust 

royalty payments and reports. 

§ 1206.51 What definitions apply to this 

subpart? 

For purposes of this subpart: 

Affiliate means a person who 

controls, is controlled by, or is under 

common control with another person. 

(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 in determining 

whether there is control in 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: 

(A) The percentage of ownership or 

common ownership; 

(B) The relative percentage of 

ownership or common ownership 

compared to the percentage(s) of 

ownership by other persons; 

(C) Whether a person is the greatest 

single owner; and 

(D) Whether there is an opposing 

voting bloc of greater ownership; 

(iii) Operation of a lease, plant, 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. 

Area means a geographic region 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, 

economic, and legal characteristics. 

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 a review, conducted 

under the generally accepted 

Governmental Auditing Standards, of 

royalty reporting and payment activities 

of lessees, designees, or other persons 

who pay royalties, rents, or bonuses on 

Indian leases. 

BLM means the Bureau of Land 

Management of the Department of the 

Interior. 

Condensate means liquid 

hydrocarbons (generally exceeding 40 

degrees of API gravity) recovered at the 

surface without resorting to processing. 

Condensate is the mixture of liquid 

hydrocarbons that results from 

condensation of petroleum 

hydrocarbons existing initially in a 

gaseous phase in an underground 

reservoir. 

Contract means any oral or written 

agreement, including amendments or 

revisions thereto, between two or more 

persons and enforceable by law that 

with due consideration creates an 

obligation. 

Designated area means an area ONRR 

designates for purposes of calculating 

Location and Crude Type Differentials 

applied to an IBMP value. ONRR will 

post designated areas on its Web site at 

www.onrr.gov. ONRR will monitor the 

market activity in the designated areas 

and, if necessary, hold a technical 

conference to review, modify, or add a 

particular designated area. ONRR will 

post any change to the designated areas 

on its Web site at www.onrr.gov. Criteria 

to determine any future changes to 

designated areas include, but are not 

limited to: Markets served, examples 

include refineries and/or market 

centers, such as Cushing, OK; Access to 

markets, examples include, access to 

similar infrastructure, such as pipelines, 

rail lines, and trucking; and/or similar 

geography, for example, no challenging 

geographical divides, large rivers and/or 

mountains. 

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, and other 

consideration. Exchange agreements: 

(1) May or may not specify prices for 

the oil involved; 

(2) Frequently specify dollar amounts 

reflecting location, quality, or other 

differentials; 

(3) 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, or in separate agreements; 

and 

(4) May include, but are not limited 

to, exchanges of produced oil for 

specific types of oil (e.g., WTI); 

exchanges of produced oil for other oil 

at other locations (location trades); 

exchanges of produced oil for other 

grades of oil (grade trades); and multiparty exchanges. 

Field means a geographic region 

situated over one or more subsurface oil 

and gas reservoirs encompassing at least 

the outermost boundaries of all oil and 

gas accumulations known to be within 

those reservoirs vertically projected to 

the land surface. Onshore fields usually 

are given names, and their official 

boundaries are often designated by oil 

and gas regulatory agencies in the 

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respective States in which the fields are 

located. 

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 as approved by BLM 

operations personnel. 

Gross proceeds means the total 

monies and other consideration 

accruing for the disposition of oil 

produced. Gross proceeds also include, 

but are not limited to, the following 

examples: 

(1) Payments for services, such as 

dehydration, marketing, measurement, 

or gathering that the lessee must 

perform at no cost to the lessor in order 

to put the production into marketable 

condition; 

(2) The value of services to put the 

production into marketable condition, 

such as salt water disposal, that the 

lessee normally performs but that the 

buyer performs on the lessee’s behalf; 

(3) Reimbursements for harboring or 

terminalling fees; 

(4) Tax reimbursements, even though 

the Indian royalty interest may be 

exempt from taxation; 

(5) Payments made to reduce or buy 

down the purchase price of oil to be 

produced in later periods, by allocating 

those payments over the production 

whose price the payment reduces and 

including the allocated amounts as 

proceeds for the production as it occurs; 

and 

(6) Monies and all other consideration 

to which a seller is contractually or 

legally entitled but does not seek to 

collect through reasonable efforts. 

IBMP means the Index-Based Major 

Portion value calculated under 

§ 1206.54. 

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. 

Lease means any contract, profit-share 

arrangement, joint venture, or other 

agreement issued or approved by the 

United States under an Indian mineral 

leasing law that authorizes exploration 

for, development or extraction of, or 

removal of lease products. Depending 

on the context, lease may also refer to 

the land area covered by that 

authorization. 

Lease products means any leased 

minerals attributable to, originating 

from, or allocated to Indian leases. 

Lessee means any person to whom the 

United States, a Tribe, or individual 

Indian mineral owner issues a lease, and 

any person who has been assigned an 

obligation to make royalty or other 

payments required by the lease. Lessee 

includes: 

(1) Any person who has an interest in 

a lease (including operating rights 

owners); and 

(2) An operator, purchaser, or other 

person with no lease interest who 

reports and/or makes royalty payments 

to ONRR or the lessor on the lessee’s 

behalf. 

Lessor means an Indian Tribe or 

individual Indian mineral owner who 

has entered into a lease. 

Like-quality oil means oil that has 

similar chemical and physical 

characteristics. 

Location and Crude Type Differential 

(LCTD) means the difference in value 

between the average of the monthly 

NYMEX Calendar Monthly Averages 

(CMA) for the previous 12 months and 

the average of the monthly Major 

Portion Prices for the previous 12 

months for a designated area for each 

crude oil type calculated under 

§ 1206.54. 

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. 

Major Portion Price means the highest 

price paid or offered at the time of 

production for the major portion of oil 

produced from the same designated area 

for the same crude oil type. 

Marketable condition means lease 

products that 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. 

Net means to reduce the reported 

sales value to account for transportation 

instead of reporting a transportation 

allowance as a separate entry on Form 

ONRR–2014. 

NYMEX Calendar Month Average 

Price means the average of the New 

York Mercantile Exchange (NYMEX) 

daily settlement prices for light sweet 

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 

nearest month of delivery for which 

NYMEX futures prices are published 

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 and 

remains liquid at atmospheric pressure 

after passing through surface separating 

facilities and is marketed or used as 

such. Condensate recovered in lease 

separators or field facilities is 

considered to be oil. 

ONRR means the Office of Natural 

Resources Revenue of the Department of 

the Interior. 

Operating rights owner, also known as 

a working interest owner, means any 

person who owns operating rights in a 

lease subject to this subpart. A record 

title owner is the owner of operating 

rights under a lease until the operating 

rights have been transferred from record 

title (see Bureau of Land Management 

regulations at 43 CFR 3100.0–5(d)). 

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 that 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 


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pressures and/or temperatures in a 

reservoir is not considered processing. 

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. 

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 

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 2012. December 

was the prompt month from October 23 

through November 20. 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 23 and November 20. P1 is 

the average of the daily NYMEX settlement 

prices for deliveries during January 

published for each business day between 

October 23 and November 20. P2 is the 

average of the daily NYMEX settlement 

prices for deliveries during February 

published for each business day between 

October 23 and November 20. 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 2012. November 

was the prompt month 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 to the buyer and 

does not retain any related rights such 

as the right to buy back similar 

quantities of oil from the buyer 

elsewhere; 

(2) The buyer pays money or other 

consideration for the oil; and 

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

the oil to occur. 

Sales type code means the contract 

type or general disposition (e.g., arm’slength or non-arm’s-length) of 

production from the lease. The sales 

type code applies to the sales contract, 

or other disposition, and not to the 

arm’s-length or non-arm’s-length nature 

of a transportation allowance. 

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 of 

moving oil to a point of sale or delivery 

off the lease, unit area, or communitized 

area. The transportation allowance does 

not include gathering costs. 

WTI means West Texas Intermediate. 

You means a lessee, operator, or other 

person who pays royalties under this 

subpart. 

§ 1206.52 How do I calculate royalty value 

for oil that I or my affiliate sell(s) or 

exchange(s) under an arm’s-length 

contract? 

(a) The value of production for royalty 

purposes for your lease is the higher of 

either the value determined under this 

section or the IBMP value calculated 

under § 1206.54. 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 § 1206.56 or § 1206.57. 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. 

(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 all 

contracts for the sale of oil produced 

from that lease. 

(c) If ONRR determines that the gross 

proceeds accruing to you or your 

affiliate does not reflect the reasonable 

value of the production due to either: 

(1) Misconduct by or between the 

parties to the arm’s-length contract; or 

(2) Breach of your duty to market the 

oil for the mutual benefit of yourself and 

the lessor, ONRR will establish a value 

based on other relevant matters. 

(i) ONRR will not use this provision 

to simply substitute its judgment of the 

market value of the oil for the proceeds 

received by the seller under an arm’slength sales contract. 

(ii) The fact that the price received by 

the seller under an arm’s-length contract 

is less than other measures of market 

price is insufficient to establish breach 

of the duty to market unless ONRR finds 

additional evidence that the seller acted 

unreasonably or in bad faith in the sale 

of oil produced from the lease. 

(d) You have the burden of 

demonstrating that your or your 

affiliate’s contract is arm’s-length. 

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(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) You must base value on the highest 

price that you or your affiliate can 

receive through legally enforceable 

claims under the oil sales contract. 

(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) This provision applies 

notwithstanding any other provisions in 

this title 30 of the Code of Federal 

Regulations to the contrary. 

(h) If you or your affiliate enter(s) into 

an arm’s-length exchange agreement, or 

multiple sequential arm’s-length 

exchange agreements, then you must 

value your oil under this paragraph. 

(1) If you or your affiliate exchange(s) 

oil at arm’s length for WTI or equivalent 

oil at Cushing, Oklahoma, you must 

value the oil using the NYMEX price, 

adjusted for applicable location and 

quality differentials under paragraph 

(h)(3) of this section and any 

transportation costs under paragraph 

(h)(4) of this section and § 1206.56 and 

§ 1206.57 or § 1206.58. 

(2) If you do not exchange oil for WTI 

or equivalent oil at Cushing, but 

exchange it at arm’s length for oil at 

another location and following the 

arm’s-length exchange(s) you or your 

affiliate sell(s) the oil received in the 

exchange(s) under an arm’s-length 

contract, then you must use the gross 

proceeds under you or your affiliate’s 

arm’s-length sales contract after the 

exchange(s) occur(s), adjusted for 

applicable location and quality 

differentials under paragraph (h)(3) of 

this section and any transportation costs 

under paragraph (h)(4) of this section 

and § 1206.56 and § 1206.57 or 

§ 1206.58. 

(3) 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 exchange agreement 

does not reflect reasonable location or 

quality differentials, ONRR may adjust 

the differentials you used based on 

relevant information. You may not 

otherwise use the price or differential 

specified in an arm’s-length exchange 

agreement to value your production. 

(4) If you value oil under this 

paragraph, ONRR will allow a 

deduction, under § 1206.56 and 

§ 1206.57 or § 1206.58, for the 

reasonable, actual costs to transport the 

oil: 

(i) From the lease to a point where oil 

is given in exchange; and 

(ii) If oil is not exchanged to Cushing, 

Oklahoma, from the point where oil is 

received in exchange to the point where 

the oil received in exchange is sold. 

(5) If you or your affiliate exchange(s) 

your oil at arm’s length, and neither 

paragraph (c)(1) nor (c)(2) of this section 

applies, ONRR will establish a value for 

the oil based on relevant matters. After 

ONRR establishes the value, you must 

report and pay royalties and any late 

payment interest owed based on that 

value. 

§ 1206.53 How do I calculate royalty value 

for oil that I or my affiliate do(es) not sell 

under an arm’s-length contract? 

(a) The value of production for royalty 

purposes for your lease is the higher of 

either the value determined under this 

section or the IBMP value calculated 

under § 1206.54. The unit value of your 

oil not sold under an arm’s-length 

contract under this section for royalty 

purposes is the volume-weighted 

average of the gross proceeds paid or 

received by you or your affiliate, 

including your refining affiliate, for 

purchases or sales under arm’s-length 

contracts. 

(1) When calculating that unit value, 

use only purchases or sales of other likequality oil produced from the field (or 

the same area if you do not have 

sufficient arm’s-length purchases or 

sales of oil produced from the field) 

during the production month. 

(2) You may adjust the gross proceeds 

determined under paragraph (a) of this 

section for transportation costs under 

paragraph (c) of this section and 

§ 1206.56 and § 1206.57 or § 1206.58 

before including those proceeds in the 

volume-weighted average calculation. 

(3) If you have purchases away from 

the field(s) and cannot calculate a price 

in the field because you cannot 

determine the seller’s cost of 

transportation that would be allowed 

under paragraph (c) of this section and 

§ 1206.56 and § 1206.57 or § 1206.58, 

you must not include those purchases in 

your volume-weighted average 

calculation. 

(b) 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. Use 

applicable gravity adjustment tables for 

the field (or the same general area for 

like-quality oil if you do not have 

gravity adjustment tables for the specific 

field) to normalize for gravity, as shown 

in the example below. 

Example (1) to paragraph (b): Assume that 

a lessee, who owns a refinery and refines the 

oil produced from the lease at that refinery, 

purchases like-quality oil from other 

producers in the same field at arm’s length 

for use as feedstock in its refinery. Further 

assume that the oil produced from the lease 

that is being valued under this section is 

Wyoming general sour with an API gravity of 

23.5°. Assume that the refinery purchases at 

arm’s-length oil (all of which must be 

Wyoming general sour) in the following 

volumes of the API gravities stated at the 

prices and locations indicated: 

10,000 bbl .................................... 24.5° $34.70/bbl ................................... Purchased in the field. 

8,000 bbl ...................................... 24.0° $34.00/bbl ................................... Purchased at the refinery after the third-party producer transported it to the refinery, and the lessee does not know the 

transportation costs. 

9,000 bbl ...................................... 23.0° $33.25/bbl ................................... Purchased in the field. 

4,000 bbl ...................................... 22.0° $33.00/bbl ................................... Purchased in the field. 

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Example (2) to paragraph (b): Because the 

lessee does not know the costs that the seller 

of the 8,000 bbl incurred to transport that 

volume to the refinery, that volume will not 

be included in the volume-weighted average 

price calculation. Further assume that the 

gravity adjustment scale provides for a 

deduction of $0.02 per 1⁄10 degree API gravity 

below 34°. Normalized to 23.5° (the gravity 

of the oil being valued under this section), 

the prices of each of the volumes that the 

refiner purchased that are included in the 

volume-weighted average calculation are as 

follows: 

10,000 bbl .................................... 24.5° $34.50/bbl ................................... (1.0° difference over 23.5° = $0.20 deducted). 

9,000 bbl ...................................... 23.0° $33.35/bbl ................................... (0.5° difference under 23.5° = $0.10 added). 

4,000 bbl ...................................... 22.0° $33.30/bbl ................................... (1.5° difference under 23.5° = $0.30 added). 

Example (3) to paragraph (b): The volumeweighted average price is ((10,000 bbl × 

$34.50/bbl) + (9,000 bbl × $33.35/bbl) + 

(4,000 bbl × $33.30/bbl))/23,000 bbl = $33.84/ 

bbl. That price will be the value of the oil 

produced from the lease and refined prior to 

an arm’s-length sale, under this section. 

(c) If you value oil under this section, 

ONRR will allow a deduction, under 

§ 1206.56 and § 1206.57 or § 1206.58, for 

the reasonable, actual costs: 

(1) That you incur to transport oil that 

you or your affiliate sell(s), which is 

included in the volume-weighted 

average price calculation, from the lease 

to the point where the oil is sold; and 

(2) That the seller incurs to transport 

oil that you or your affiliate purchase(s), 

which is included in the volumeweighted average cost calculation, from 

the property where it is produced to the 

point where you or your affiliate 

purchase(s) it. You may not deduct any 

costs of gathering as part of a 

transportation deduction or allowance. 

(d) If paragraphs (a) and (b) 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. 

§ 1206.54 How do I fulfill the lease 

provision regarding valuing production on 

the basis of the major portion of like-quality 

oil? 

(a) This section applies to any Indian 

leases that contain a major portion 

provision for determining value for 

royalty purposes. This section also 

applies to any Indian leases that provide 

that the Secretary may establish value 

for royalty purposes. The value of 

production for royalty purposes for your 

lease is the higher of either the value 

determined under this section or the 

gross proceeds you calculated under 

§ 1206.52 or § 1206.53. 

(b) You must submit a monthly Form 

ONRR–2014 using the higher of IBMP 

value determined under this section or 

your gross proceeds under § 1206.52 or 

§ 1206.53. Your Form ONRR–2014 must 

meet the requirements of 30 CFR 

1210.61 of this chapter. 

(c) ONRR will determine the monthly 

IBMP value for each designated area and 

crude oil type and post those values on 

its Web site at www.onrr.gov. The 

monthly IBMP value by designated area 

and crude oil type is calculated as 

follows: 

(d) ONRR will calculate the LCTD for 

each designated area (the same 

designated areas posted on its Web site 

at www.onrr.gov) and crude oil type 

using the following formula: 

(1) For the first full production month 

after this rule is effective, ONRR will 

calculate the monthly Major Portion 

Prices using data reported on the Form 

ONRR–2014 for the previous 12 

production months prior to the effective 

date of this rule (Previous Twelve 

Months). To the extent ONRR does not 

have data on the Form ONRR–2014 

regarding the crude oil type for the 

entire previous twelve months, ONRR 

will assume the crude oil type is the 

same for those months for which ONRR 

does not have data as the months for 

which the crude oil type was reported 

on the Form ONRR–2014 for the same 

leases and/or agreements. 

(i) ONRR will array the calculated 

prices net of transportation by month 

from highest to lowest price for each 

designated area and crude oil type. For 

each month, ONRR will calculate the 

Major Portion Price as that price at 

which 25 percent plus 1 barrel (by 

volume) of the oil (starting from the 

highest) is sold; 

(ii) To calculate the average of the 

monthly Major Portion Prices for the 

previous 12 months, ONNR will add the 

monthly Major Portion Prices calculated 

in paragraph (A) and divide by 12. 

(2) For every month following the first 

full production month after this rule is 

effective, ONRR will monitor the LCTD 

using data reported on the Form ONRR– 

2014 for the previous month. 

(i) ONRR will use the oil sales volume 

reported by lessees on Form ONRR– 

2014 to monitor and, if necessary, to 

modify the LCTD used in the IBMP 

value. 


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(ii) ONRR will monitor oil sales 

volumes not reported under the sales 

type code OINX, as provided in 30 CFR 

1210.61(a) and (b), on the Form ONRR– 

2014 on a monthly basis by designated 

area and crude oil type. 

(iii) If the monthly oil sales volumes 

not reported under the sales type code 

OINX varies +/¥3 percent from 25 

percent of the total reported oil sales 

volume for the month, then ONRR will 

revise the LCTD prospectively starting 

with the following month. 

(A) If monthly oil sales volumes not 

reported under the sales type code 

OINX on the Form ONRR–2014 by the 

designated area and crude oil type fall 

below 22 percent, ONRR will increase 

the LCTD by 10 percent every month 

until the monthly oil sales volumes 

reported under the sales type code for 

gross proceeds on the Form ONRR–2014 

fall within the +/¥3 percent range. In 

Example 1, assume the IBMP value is 

$81.06 and the LCTD for the designated 

area is 14.28%. In the table below, the 

Percent of Volume not as OINX reported 

is less than 22%, which triggers a 

modification to the LCTD. ONRR will 

adjust the LCTD upward by 10% 

(14.28% × 1.10). Therefore, for the next 

month the LCTD will be 15.71%. In the 

following month, the IBMP value will 

equal the next month’s NYMEX CMA 

multiplied by (1 ¥ 0.1571). ONRR will 

continue to make adjustments in 

subsequent months, until monthly sales 

volumes not reported as OINX fall 

within 22–28% of total monthly sales 

volume. 

EXAMPLE 1—DIFFERENTIAL ADJUSTMENT WHEN ARMS SALES VOLUME FOR THE CURRENT MONTH FALLS BELOW 22% 

OF TOTAL MONTHLY SALES VOLUME

Lease Sales 

volume 

Unit 

price 

Sales type 

code 

Cumulative 

volume 

Percent of 

volume 

1 .............................................................................................. 220 81.95 ARMS 220 9.02 

2 .............................................................................................. 275 81.71 ARMS 495 20.29 

3 .............................................................................................. 400 81.06 OINX 895 36.68 

4 .............................................................................................. 425 81.06 OINX 1,320 54.10 

5 .............................................................................................. 370 81.06 OINX 1,690 69.26 

6 .............................................................................................. 400 81.06 OINX 2,090 85.66 

7 .............................................................................................. 350 81.06 OINX 2,440 100.00 

2,440 

(B) If monthly oil sales volumes not 

reported under the sales type code 

OINX on the Form ONRR–2014 by 

designated area and crude oil type 

exceed 28 percent, then ONRR will 

decrease the LCTD by 10 percent every 

month until the monthly oil sales 

volumes reported under the sales type 

code for gross proceeds on the Form 

ONRR–2014 fall within the +/¥3 

percent range. In Example 2, assume the 

IBMP value is $81.06 and the LCTD is 

14.28%. However, as noted in the table 

below, the Percent of Volume not 

reported as OINX is 32.69%, exceeding 

the 28% threshold, which triggers a 

modification to the LCTD. ONRR will 

adjust the LCTD downward by 10% 

(14.28% × 0.90). Therefore, for the next 

month the LCTD will be 12.85%. In the 

following month, the IBMP will equal 

the next month’s NYMEX CMA 

multiplied by (1 ¥ 0.1285). ONRR will 

continue to make adjustments in 

subsequent months, until monthly sales 

volumes reported as ARMS fall within 

22–28% of total monthly sales volume. 

EXAMPLE 2—DIFFERENTIAL ADJUSTMENT WHEN ARMS SALES VOLUME NOT REPORTED AS OINX FOR THE CURRENT

MONTH EXCEEDS 28% OF TOTAL MONTHLY SALES VOLUME

Lease Sales 

volume 

Unit 

price 

Sales type 

code 

Cumulative 

volume 

Percent of 

volume 

1 .............................................................................................. 230 81.95 ARMS 230 11.06 

2 .............................................................................................. 275 81.71 ARMS 505 24.28 

3 .............................................................................................. 175 81.45 ARMS 680 32.69 

4 .............................................................................................. 250 81.06 OINX 930 44.71 

5 .............................................................................................. 425 81.06 OINX 1,355 65.14 

6 .............................................................................................. 325 81.06 OINX 1,680 80.77 

7 .............................................................................................. 400 81.06 OINX 2,080 100.00 

2,080 

(e) In areas where there is insufficient 

data reported to ONRR on Form ONRR– 

2014 to determine a differential for a 

specific crude oil type, ONRR will use 

its discretion to determine an 

appropriate IBMP value. 

§ 1206.55 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 Indian lessor 

unless the lease agreement provides 

otherwise. 

(b) If you must use gross proceeds 

under an arm’s-length contract or your 

affiliate’s gross proceeds under an 

arm’s-length exchange agreement to 

determine value under 30 CFR 1206.52 

or 1206.53, 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. 

§ 1206.56 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 § 1206.52 or § 1206.53, as 

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35118 Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 

applicable. You may not deduct 

transportation costs to reduce royalties 

where you did not incur any costs to 

move a particular volume of oil. ONRR 

will not grant a transportation 

allowance for transporting oil taken as 

Royalty-In-Kind (RIK). 

(b)(1) Except as provided in paragraph 

(b)(2) of this section, your transportation 

allowance deduction on the basis of a 

sales type code may not exceed 50 

percent of the value of the oil at the 

point of sale as determined under 

§ 1206.52 of this subpart. Transportation 

costs cannot be transferred between 

sales type codes or to other products. 

(2) Upon your request, ONRR may 

approve a transportation allowance 

deduction in excess of the limitation 

prescribed by paragraph (b)(1) of this 

section. You must demonstrate that the 

transportation costs incurred in excess 

of the limitation prescribed in paragraph 

(b)(1) of this section were reasonable, 

actual, and necessary. An application 

for exception (using Form ONRR–4393, 

Request to Exceed Regulatory 

Allowance Limitation) must contain all 

relevant and supporting documentation 

necessary for ONRR to make a 

determination. Under no circumstances 

may the value, for royalty purposes, 

under any sales type code, be reduced 

to zero. 

(c) You must express transportation 

allowances for oil in dollars per barrel. 

If you or your affiliate’s payments for 

transportation under a contract are not 

on a dollar per barrel basis, you must 

convert whatever consideration you or 

your affiliate are paid to a dollar per 

barrel equivalent. 

(d) You must allocate transportation 

costs among all products produced and 

transported as provided in § 1206.57. 

(e) All transportation allowances are 

subject to monitoring, review, audit, and 

adjustment. 

(f) If, after a review or audit, ONRR 

determines you have improperly 

determined a transportation allowance 

authorized by this subpart, then you 

must pay any additional royalties due, 

plus late payment interest calculated 

under § 1218.54 of this chapter or report 

a credit for, or request a refund of, any 

overpaid royalties without interest 

under § 1218.53 of this chapter. 

(g) You may not deduct any costs of 

gathering as part of a transportation 

deduction or allowance. 

§ 1206.57 How do I determine a 

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

(a) Arm’s-length transportation. (1) If 

you incur transportation costs under an 

arm’s-length contract, your 

transportation allowance is the 

reasonable, actual costs you incur to 

transport oil under that contract. You 

have the burden of demonstrating that 

your contract is arm’s-length. 

(2) Before you may take any 

deduction, you must submit a 

completed page one and Schedule 1 of 

Form ONRR–4110, Oil Transportation 

Allowance Report, under paragraph 

(b)(1) of this section. 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 

you filed Form MMS–4110 with ONRR, 

unless ONRR approves a longer period 

upon you showing good cause. 

(3) If ONRR determines that the 

consideration paid under an arm’slength transportation contract does not 

reflect the reasonable value of the 

transportation because of misconduct by 

or between the contracting parties, or 

because the lessee otherwise has 

breached its duty to the lessor to market 

the production for the mutual benefit of 

the lessee and the lessor, then ONRR 

shall require that the transportation 

allowance be determined in accordance 

with paragraph (b) of this section. When 

ONRR determines that the value of the 

transportation may be unreasonable, 

ONRR will notify the lessee and give the 

lessee an opportunity to provide written 

information justifying the lessee’s 

transportation costs.(4)(i) If an arm’slength transportation contract includes 

more than one liquid product, and the 

transportation costs attributable to each 

product cannot be determined from the 

contract, then you must allocate the 

total transportation costs in a consistent 

and equitable manner to each of the 

liquid products transported in the same 

proportion as the ratio of the volume of 

each product (excluding waste products 

which have no value) to the volume of 

all liquid products (excluding waste 

products which have no value). Except 

as provided in this paragraph, you may 

not take an allowance for the costs of 

transporting lease production which is 

not royalty-bearing without ONRR 

approval. 

(ii) Notwithstanding the requirements 

of paragraph (4)(i) of this section, you 

may propose to ONRR a cost allocation 

method on the basis of the values of the 

products transported. ONRR shall 

approve the method unless it 

determines it is not consistent with the 

purposes of the regulations in this part. 

(5) If an arm’s-length transportation 

contract includes both gaseous and 

liquid products, and the transportation 

costs attributable to each product cannot 

be determined from the contract, you 

must propose an allocation procedure to 

ONRR. 

(i) You may use the oil transportation 

allowance determined in accordance 

with its proposed allocation procedure 

until ONRR issues its determination on 

the acceptability of the cost allocation. 

(ii) You must submit to ONRR all 

available data to support your proposal. 

(iii) You must submit your initial 

proposal within 3 months after the last 

day of the month for which you request 

a transportation allowance, whichever is 

later (unless ONRR approves a longer 

period). 

(iv) ONRR will determine the oil 

transportation allowance based on your 

proposal and any additional information 

ONRR deems necessary. 

(6) Where an arm’s-length sales 

contract price includes a provision 

whereby the listed price is reduced by 

a transportation factor, ONRR will not 

consider the transportation factor to be 

a transportation allowance. You may 

use the transportation factor to 

determine your gross proceeds for the 

sale of the product. The transportation 

factor may not exceed 50 percent of the 

base price of the product without ONRR 

approval. 

(b) Reporting requirements. (1) With 

the exception of the transportation 

allowances specified in paragraph (b)(5) 

of this section, you must submit page 

one and Schedule 1 of the initial Form 

ONRR–4110, Oil Transportation 

Allowance Report, prior to, or at the 

same time as you report the 

transportation allowance you 

determined under an arm’s-length 

contract on Form ONRR–2014, Report of 

Sales and Royalty Remittance. If ONRR 

receives your Form ONRR–4110 by the 

end of the month the Form ONRR–2014 

is due, ONRR will consider it timely 

received. 

(2) Your initial Form ONRR–4110 is 

effective for a reporting period 

beginning the month you are first 

authorized to deduct a transportation 

allowance and will continue until the 

end of the calendar year, or until the 

applicable contract or rate terminates or 

is modified or amended, whichever is 

earlier. 

(3) After the initial reporting period 

and for succeeding reporting periods, 

you must submit page one and Schedule 

1 of Form ONRR–4110 within 3 months 

after the end of the calendar year, or 

after the applicable contract or rate 

terminates or is modified or amended, 

whichever is earlier, unless ONRR 

approves a longer period (during which 

period you must continue to use the 

allowance from the previous reporting 

period). 

(4) ONRR may require you to submit 

arm’s-length transportation contracts, 

production agreements, operating 

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agreements, and related documents. You 

must submit documents within a 

reasonable time ONRR determines. 

(5) ONRR may establish, in 

appropriate circumstances, reporting 

requirements which are different from 

the requirements of this section. 

§ 1206.58 How do I determine a 

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

have no contract? 

(a) Non-arm’s-length or no contract. 

(1) If you have a non-arm’s-length 

transportation contract or no contract, 

including those situations where you or 

your affiliate perform(s) transportation 

services for you, the transportation 

allowance is based on your reasonable, 

actual costs as provided in this 

paragraph. 

(2) Before you may take any estimated 

or actual deduction, you must submit a 

completed Form ONRR–4110 in its 

entirety under paragraph (b) of this 

section. 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 you filed Form 

ONRR–4110 with ONRR, unless ONRR 

approves a longer period upon you 

showing good cause. 

(3) You must base a transportation 

allowance for non-arm’s-length or nocontract situations on your actual costs 

for transportation during the reporting 

period, including operating and 

maintenance expenses, overhead, and 

either depreciation and a return on 

undepreciated capital investment under 

paragraph (a)(3)(iv)(A) of this section, or 

a cost equal to the initial capital 

investment in the transportation system 

multiplied by a rate of return under 

paragraph (a)(3)(iv)(B) of this section. 

Allowable capital 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. 

(i) Allowable operating expenses 

include: Operations supervision and 

engineering; operations labor; fuel; 

utilities; materials; ad valorem property 

taxes; rent; supplies; and any other 

directly allocable and attributable 

operating expense which the lessee can 

document. 

(ii) Allowable maintenance expenses 

include: Maintenance of the 

transportation system; maintenance of 

equipment; maintenance labor; and 

other directly allocable and attributable 

maintenance expenses which the lessee 

can document. 

(iii) 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. 

(iv) You may use either depreciation 

or a return on depreciable capital 

investment. After you have elected to 

use either method for a transportation 

system, you may not later elect to 

change to the other alternative without 

approval of ONRR. 

(A) To compute depreciation, 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 transportation system 

services or on a unit-of-production 

method. After you make an election, 

you may not change methods without 

ONRR approval. A change in ownership 

of a transportation system shall not alter 

the depreciation schedule the original 

transporter/lessee established for 

purposes of the allowance calculation. 

With or without a change in ownership, 

a transportation system shall be 

depreciated only once. You may not 

depreciate equipment below a 

reasonable salvage value. 

(B) ONRR will allow as a cost an 

amount equal to the initial capital 

investment in the transportation system 

multiplied by the rate of return 

determined under paragraph (a)(3)(v) of 

this section. No allowance shall be 

provided for depreciation. 

(v) The rate of return is the industrial 

rate associated with Standard and Poor’s 

BBB rating. The rate of return you must 

use is the monthly average rate as 

published in Standard and Poor’s Bond 

Guide for the first month of the 

reporting period for which the 

allowance is applicable and is effective 

during the reporting period. You must 

redetermine the rate at the beginning of 

each subsequent transportation 

allowance reporting period (which is 

determined under paragraph (b) of this 

section). 

(4)(i) You must determine the 

deduction for transportation costs based 

on your or your affiliate’s cost of 

transporting each product through each 

individual transportation system. Where 

more than one liquid product is 

transported, you must allocate costs to 

each of the liquid products transported 

in the same proportion as the ratio of 

the volume of each liquid product 

(excluding waste products which have 

no value) to the volume of all liquid 

products (excluding waste products 

which have no value) and you must 

make such allocation in a consistent and 

equitable manner. Except as provided in 

this paragraph, you may not take an 

allowance for transporting lease 

production which is not royalty-bearing 

without ONRR approval. 

(ii) Notwithstanding the requirements 

of paragraph (4)(i) of this section, you 

may propose to ONRR a cost allocation 

method on the basis of the values of the 

products transported. ONRR will 

approve the method unless it 

determines that it is not consistent with 

the purposes of the regulations in this 

part. 

(5) Where both gaseous and liquid 

products are transported through the 

same transportation system, you must 

propose a cost allocation procedure to 

ONRR. 

(i) You may use the oil transportation 

allowance determined in accordance 

with its proposed allocation procedure 

until ONRR issues its determination on 

the acceptability of the cost allocation. 

(ii) You must submit to ONRR all 

available data to support your proposal. 

(iii) You must submit your initial 

proposal within 3 months after the last 

day of the month for which you request 

a transportation allowance, whichever is 

later (unless ONRR approves a longer 

period). 

(iv) ONRR will determine the oil 

transportation allowance based on your 

proposal and any additional information 

ONRR deems necessary. 

(6) You may apply to ONRR for an 

exception from the requirement that you 

compute actual costs under paragraphs 

(a)(1) through (a)(5) of this section. 

(i) ONRR will grant the exception 

only if you have a tariff for the 

transportation system the Federal 

Energy Regulatory Commission (FERC) 

has approved for Indian leases. 

(ii) ONRR will deny the exception 

request if it determines the tariff is 

excessive as compared to arm’s-length 

transportation charges by pipelines, 

owned by the lessee or others, providing 

similar transportation services in that 

area. 

(iii) If there are no arm’s-length 

transportation charges, ONRR will deny 

the exception request if: 

(A) No FERC cost analysis exists and 

the FERC has declined to investigate 

under ONRR timely objections upon 

filing; and 

(B) The tariff significantly exceeds the 

lessee’s actual costs for transportation as 

determined under this section. 

(b) Reporting requirements. (1) With 

the exception of those transportation 

allowances specified in paragraphs 

(b)(1)(v), (b)(1)(vii) and (b)(1)(viii) of this 

section, you must submit an initial 

Form ONRR–4110 prior to, or at the 

same time as, the transportation 

allowance you determine under a nonarm’s-length contract or no-contract 

situation is reported on Form ONRR– 

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35120 Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 

2014. If ONRR receives your Form 

ONRR–4110 by the end of the month the 

Form ONRR–2014 is due, ONRR will 

consider it timely received. You may 

base the initial report on estimated 

costs. 

(ii) Your initial Form ONRR–4110 is 

effective for a reporting period 

beginning the month you are first 

authorized to deduct a transportation 

allowance and will continue until the 

end of the calendar year, or until 

transportation under the non-arm’slength contract or the no-contract 

situation terminates, whichever is 

earlier. 

(iii) After the initial reporting period, 

you must submit a completed Form 

ONRR–4110 containing the actual costs 

for the previous reporting period. If oil 

transportation is continuing, you must 

include on Form ONRR–4110 your 

estimated costs for the next calendar 

year. You must estimate your oil 

transportation allowance based on the 

actual costs for the previous reporting 

period plus or minus any adjustments 

which are based on your knowledge of 

decreases or increases that will affect 

the allowance. ONRR must receive the 

Form ONRR–4110 within 3 months after 

the end of the previous reporting period, 

unless ONRR approves a longer period 

(during which period you must 

continue to use the allowance from the 

previous reporting period). 

(iv) For new transportation facilities 

or arrangements, your initial Form 

ONRR–4110 must include estimates of 

the allowable oil transportation costs for 

the applicable period. You must base 

cost estimates on the most recently 

available operations data for the 

transportation system or, if such data 

are not available, you must use 

estimates based upon industry data for 

similar transportation systems. 

(v) Non-arm’s-length contract or nocontract transportation allowances 

which are in effect at the time these 

regulations become effective are allowed 

to continue until such allowances 

terminate. For the purposes of this 

section, only those allowances ONRR 

has approved in writing qualify as being 

in effect at the time these regulations 

become effective. 

(vi) ONRR may require you to submit 

all data you used to prepare your Form 

ONRR–4110. You must submit the data 

within a reasonable period of time 

ONRR determines. 

(vii) ONRR may establish, in 

appropriate circumstances, reporting 

requirements which are different from 

the requirements of this section. 

(viii) If you are authorized to use your 

FERC-approved tariff as your 

transportation cost under paragraph 

(a)(6) of this section, you must follow 

the reporting requirements of 

§ 1206.57(b). 

(3) ONRR may establish reporting 

dates for you that are different from 

those specified in this subpart to 

provide more effective administration. 

We will notify you of any change in 

your reporting period. 

(4) You must report transportation 

allowances as a separate entry on Form 

ONRR–2014 unless ONRR approves a 

different reporting procedure. 

(c) Notwithstanding any other 

provisions of this subpart, for other than 

arm’s-length contracts, no cost shall be 

allowed for oil transportation which 

results from payments (either 

volumetric or for value) for actual or 

theoretical losses. This section does not 

apply when the transportation 

allowance is based upon a FERC or State 

regulatory agency approved tariff. 

(d) The provisions of this section shall 

apply to determine transportation costs 

when establishing value using a netback 

valuation procedure or any other 

procedure that requires deduction of 

transportation costs. 

§ 1206.59 What interest applies if I 

improperly report a transportation 

allowance? 

(a) If you deduct a transportation 

allowance on Form ONRR–2014 without 

complying with the requirements of 

§ 1206.56 and § 1206.57 or § 1206.58, 

you must pay additional royalties due, 

plus late payment interest calculated 

under § 1218.54 of this chapter. 

(b) If you erroneously report a 

transportation allowance which results 

in an underpayment of royalties, you 

must pay any additional royalties due, 

plus late payment interest calculated 

under § 1218.54 of this chapter. 

§ 1206.60 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 of this 

chapter from first day of the first month 

you were authorized to deduct a 

transportation allowance 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 may report 

a credit for, or request a refund of, any 

overpaid royalties without interest 

under § 1218.53 of this chapter. 

(c) If you make an adjustment under 

paragraph (a) or (b) of this section, then 

you must submit a corrected Form 

ONRR–2014 to reflect actual costs, 

together with any payment, using 

instructions ONRR provides. 

§ 1206.61 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. 

(2) If ONRR directs you to use a 

different royalty value, you must pay 

any additional royalties due, plus late 

payment interest calculated under 

§ 1218.54 of this chapter or you may 

report a credit for, or request a refund 

of, any overpaid royalties without 

interest under § 1218.53 of this chapter. 

(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, you must value the oil 

sold as the total consideration accruing 

to you or your affiliate. 

§ 1206.62 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 Indian Affairs 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: 

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Federal Register / Vol. 79, No. 118 / Thursday, June 19, 2014 / Proposed Rules 35121 

(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 Indian Affairs 

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 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, the Indian lessor, 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 § 1206.65. 

§ 1206.63 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 approves. 

(b) If you determine the value of oil 

under § 1206.52, § 1206.53, or § 1206.54 

of this subpart based on a quantity and/ 

or quality that is different from the 

quantity and/or quality at the point of 

royalty settlement BLM approves for the 

lease, 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 incurred 

before the royalty settlement point 

unless BLM determines that any actual 

loss was unavoidable. 

§ 1206.64 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) On request, you must make 

available sales, volume, and 

transportation data for production you 

sold, purchased, or obtained from the 

field or area. You must make this data 

available to ONRR, Indian 

representatives, or other authorized 

persons. 

(c) You can find recordkeeping 

requirements in §§ 1207.5, 1212.50, and 

1212.51 of this chapter. 

(d) ONRR, Indian representatives, or 

other authorized persons may review 

and audit your data, and ONRR will 

direct you to use a different value if they 

determine that the reported value is 

inconsistent with the requirements of 

this subpart. 

§ 1206.65 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. 

PART 1210—FORMS AND REPORTS 

■ 3. The authority citation for part 1210 

continues to read as follows: 

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

396, 2107; 30 U.S.C. 189, 190, 359, 1023, 

1751(a); 31 U.S.C. 3716, 9701; 43 U.S.C. 

1334, 1801 et seq.; and 44 U.S.C. 3506(a). 

Subpart B—Royalty Reports—Oil, Gas, 

and Geothermal Resources 

■ 4. Add § 1210.61 to subpart B to read 

as follows: 

§ 1210.61 What additional reporting 

requirements must I meet for Indian oil 

valuation purposes? 

(a) If you must report and pay under 

§ 1206.52 of this chapter, you must use 

Sales Type Code ARMS on Form 

ONRR–2014. 

(b) If you must report and pay under 

§ 1206.53 of this chapter, you must use 

Sales Type Code NARM on Form 

ONRR–2014. 

(c) If you must report and pay under 

§ 1206.54 of this chapter, you must use 

Sales Type Code OINX on Form ONRR– 

2014; 

(d) You must report one of the 

following crude oil types in the product 

code field of Form ONRR–2014: 

(1) Sweet (code 61); 

(2) Sour (code 62); 

(3) Asphaltic (code 63); 

(4) Black Wax (code 64); or 

(5) Yellow Wax (code 65); 

(e) All of the remaining requirements 

of this subpart apply. 

[FR Doc. 2014–13967 Filed 6–18–14; 8:45 am] 

BILLING CODE 4310–T2–P 

DEPARTMENT OF EDUCATION 

34 CFR Chapter III 

[Docket ID ED–2014–OSERS–0072; CFDA 

Number: 84.264A] 

Proposed Priority—Rehabilitation 

Training; Job-Driven Vocational 

Rehabilitation Technical Assistance 

Center 

AGENCY: Office of Special Education and 

Rehabilitative Services, Department of 

Education. 

ACTION: Proposed priority. 

SUMMARY: The Assistant Secretary for 

Special Education and Rehabilitative 

Services proposes a priority to establish 

a Job-Driven Vocational Rehabilitation 

Technical Assistance Center. The 

Assistant Secretary may use this priority 

for competitions in fiscal year (FY) 2014 

and later years. We take this action to 

provide training and technical 

assistance to improve the capacity of 

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