[Federal Register Volume 81, Number 127 (Friday, July 1, 2016)]
[Rules and Regulations]
[Pages 43338-43402]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-15420]



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Vol. 81

Friday,

No. 127

July 1, 2016

Part II





Department of the Interior





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Office of Natural Resources Revenue





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30 CFR Parts 1202 and 1206





Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation 
Reform; Final Rule

  Federal Register / Vol. 81 , No. 127 / Friday, July 1, 2016 / Rules 
and Regulations  

[[Page 43338]]


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DEPARTMENT OF THE INTERIOR

Office of Natural Resources Revenue

30 CFR Parts 1202 and 1206

[Docket No. ONRR-2012-0004; DS63644000 DR2PS0000.CH7000 167D0102R2]
RIN 1012-AA13


Consolidated Federal Oil & Gas and Federal & Indian Coal 
Valuation Reform

AGENCY: Office of Natural Resources Revenue (ONRR), Interior.

ACTION: Final rule.

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SUMMARY: ONRR is amending our regulations governing valuation, for 
royalty purposes, of oil and gas produced from Federal onshore and 
offshore leases and coal produced from Federal and Indian leases. This 
rule also consolidates definitions for oil, gas, and coal product 
valuation into one subpart that is applicable to the Federal oil and 
gas and Federal and Indian coal subparts.

DATES: Effective date: January 1, 2017.

FOR FURTHER INFORMATION CONTACT: For questions on technical issues, 
contact Amy Lunt at (303) 231-3746, Lisa Dawson at (303) 231-3653, Karl 
Wunderlich at (303) 231-3663, Chris Carey at (303) 231-3460, Megan 
Hessee at (303) 231-3713, Richard Adamski at (202) 513-0598, or Carrie 
Wallace at (303) 445-0638.

SUPPLEMENTARY INFORMATION: 

I. Background

    The purpose of implementing this final rule regarding the valuation 
of oil and gas production from Federal leases and coal production from 
Federal and Indian leases is (1) to offer greater simplicity, 
certainty, clarity, and consistency in product valuation for mineral 
lessees and mineral revenue recipients; (2) to ensure that Indian 
mineral lessors receive the maximum revenues from coal resources on 
their land, consistent with the Secretary's trust responsibility and 
lease terms; (3) to decrease industry's cost of compliance and ONRR's 
cost to ensure industry compliance; and (4) to provide early certainty 
to industry and to ONRR that companies have paid every dollar due.
    Also, this final rule makes non-substantive technical or clarifying 
changes to the proposed rule. We re-wrote sections of the regulations 
in Plain Language to meet the criteria of Executive Orders 12866 and 
12988 and the Presidential Memorandum of June 1, 1998, and to make our 
rules more clear, consistent, and readable.

II. Comments on Proposed Rule

    On January 6, 2015, ONRR published a Proposed Rule to amend the 
valuation regulations for oil, gas, and coal produced from Federal 
leases and coal produced from Indian leases (80 FR 608). The proposed 
rule took into consideration input that we received on the Advance 
Notices of Proposed Rulemaking, which we published on May 27, 2011, 
regarding the valuation of oil, gas, and coal produced from Federal 
leases and coal produced from Indian leases (76 FR 30878, 30881). ONRR 
also considered input that we received during six public workshops that 
we held in September and October of 2011. The proposed rulemaking 
provided for a 60-day comment period, which closed on March 9, 2015. In 
response to over 50 stakeholder requests to extend the public comment 
period, we published a notice that granted a 60-day extension, which 
extended the comment period to May 8, 2015 (80 FR 7994). During the 
public comment period, we received more than 1,000 pages of written 
comments from over 300 commenters and over 190,000 petition 
signatories. We received comments from industry, industry trade groups, 
Congress, State governors, States, local municipalities, two Tribes, 
local businesses, public interest groups, and individual commenters. 
The petition signatories' main focus was on coal, and they aligned 
themselves with organizations that were either passionately against the 
further expansion of mining coal or were proponents of coal mining.
    We carefully considered all of the public comments that we received 
during the rulemaking process and, in some instances, revised the 
language of the final rule based on these comments. We hereby adopt 
final regulations governing the valuation of oil, natural gas, and coal 
produced from Federal leases and coal produced from Indian leases. 
These regulations apply, prospectively, to oil, natural gas, and coal 
produced on or after the effective date that we have specified in the 
DATES section of this preamble.

General Comments

    Because this final rule is composed of four subparts covering 
Federal oil and gas and Federal and Indian coal, we will organize, 
analyze, and respond to the comments regarding the specific subparts.
    Public Comment: All of the over 190,000 petition signatories that 
ONRR received during the public comment period pertained to coal. The 
comments and positions on coal production and values were polarized 
representing those supporting the coal industry and those supporting 
the platform highlighting green energy and coal's harm to the 
environment. The overwhelming majority of the signed petitions were 
from individuals asserting that coal production should cease and stay 
in the ground or that ONRR's proposed changes to coal valuation do not 
go far enough toward closing the perceived loopholes that the coal 
industry is exploiting. Many commenters who work in the coal industry 
or live in coal mining-dependent communities, along with one Tribe, 
maintain that the proposed rule goes too far. They argue that the rule 
imposes unwarranted valuation methods, including the ``default 
provision,'' which, they contend, hinders transparency and creates 
complex and subjective coal valuations. They claim that the wholesale 
changes to the rule would cause irreparable economic harm to the coal 
industry by negatively disrupting the coal market.
    ONRR Response: We appreciate the comments on both sides of the 
issue. The comments regarding keeping coal in the ground or regarding 
coal's negative impact on the socioeconomic health of communities by 
discouraging production, however, are beyond the scope of this 
rulemaking, which is limited to the valuation of coal produced from 
Federal and Indian leases for royalty collection purposes. We will, 
however, respond to the specific comments that suggested more stringent 
alternative valuation methods in the section-by-section analysis part 
of the preamble. As a general matter, many commenters have concerns 
about how the Federal Government leases coal, the amount of royalty 
charged, and whether taxpayers are getting a fair return from public 
resources. While this rule takes steps toward ensuring that the 
valuation process for Federal and Indian coal resources better reflects 
the changing energy industry while protecting taxpayers and Indian 
assets, its scope is not broad enough to address the many concerns the 
commenters raised. For that and other reasons, the U.S. Department of 
the Interior (Department) recently launched a comprehensive review to 
identify and evaluate potential reforms to the Ffederal coal program in 
order to ensure that it is properly structured to provide a fair return 
to taxpayers and reflect its impacts on the environment, while 
continuing to help meet our energy needs.
    ONRR request for comments: In the proposed rule, we solicited 
comments on how to simplify and improve the

[[Page 43339]]

valuation of coal disposed of in non-arm's-length transactions and no-
sale situations. We sought input on the merits of eliminating the 
benchmarks for valuation of non-arm's-length sales and comments on the 
following questions:
     Should the royalty value of coal initially sold under non-
arm's-length conditions be based on the gross proceeds received from 
the first arm's-length sale of that coal in situations where there is a 
subsequent arm's-length sale?
     If you are a coal lessee, will adoption of this 
methodology substantively impact your current calculation and payment 
of royalties on coal, and how?
     What other methods might ONRR use to determine the royalty 
value of coal not sold at arm's-length that we may not have considered?
    Public Comment: ONRR received only one response from an industry 
commenter addressing these questions. The commenter answered no to the 
first question and explained that valuing coal further away from the 
lease may not represent the true value of the coal at the lease. The 
commenter also added that the seller may not know who the first arm's-
length purchaser may be. In response to the second question, the 
commenter believes that any subsequent transaction to an affiliate is 
not applicable to the marketability of the coal at the lease and that 
ONRR may or may not get a reasonable price for the valuation of the 
coal. The commenter responded to ONRR's third question seeking other 
methods by stating that ONRR should retain the benchmarks. The 
commenter further elaborated that the benchmarks should be reordered to 
1, 4, 2, 3, and 5, plus adding a sixth benchmark (review of actual cost 
of production and assess a return on investment that is fair to the 
situation and/or the company under assessment), applicable only in 
those rare instances when no arm's-length sales are available.
    ONRR also received several comments suggesting the option to base 
the value of coal on an index price.
    ONRR Response: The best indication of value is the gross proceeds 
received under an arm's-length contract between independent persons who 
are not affiliates and who have opposing economic interests regarding 
that contract. The best indicator of value under a non-arm's-length 
sale is the gross proceeds accruing to the lessee or its affiliate 
under the first arm's-length contract, less applicable allowances. In 
this final rule, we eliminated the benchmarks for both natural gas and 
coal. We implemented this method for Federal oil in 2000 and, in this 
final regulation, made it consistent for Federal gas and Federal and 
Indian coal.
    ONRR is not currently aware of any published index prices for coal 
that cover a wide array of coal production that are both transparent 
and widely traded so as to yield a reasonable value that would 
represent the true market value of coal. We will monitor the coal 
market and may be open to considering index prices as a valuation 
option, if viable.
    Public Comment: ONRR received a few general comments concerning 
Federal oil and natural gas production. These comments fell into 
several categories, including natural gas measurement methods, ONRR's 
unbundling program, and the economic impact on the oil and gas 
industry.
    ONRR also received general comments concerning Federal and Indian 
coal production. These comments fell into several categories, including 
the final rule's impact on coal production and the coal industry, 
royalty rates, and creating more transparency to the public for coal 
valuation.
    ONRR Response: Some of these comments were beyond the scope of the 
rule so ONRR did not address them specifically. We addressed other 
comments in the specific comment sections.
    Regarding the comments on coal royalty rates, the royalty rate is a 
lease clause and is not a component of this final rule. Royalty rates 
are a part of lease negotiations, which the Bureau of Land Management 
(BLM), Bureau of Ocean Energy Management (BOEM), and Bureau of Indian 
Affairs (BIA) on behalf of the Tribes and individual Indian mineral 
owners conduct. The final rule does not limit or otherwise infringe on 
the authority of these entities to negotiate those leases. Instead, 
this rule is focused on ensuring that Federal and Indian mineral owners 
receive the royalties that are owed to them based on the value of the 
resources being sold and consistent with the royalty terms of the 
applicable leases negotiated by the BLM, BOEM and BIA.
    As to comments related to increasing transparency, the U.S. 
Department of the Interior (Department) created a data portal as part 
of the Extractive Industries Transparency Initiative--a global, 
voluntary partnership to strengthen the accountability of natural 
resource revenue reporting and build public trust for the governance of 
these vital activities. You can access the data portal at https://useiti.doi.gov.

A. Specific Comments on 30 CFR Part 1206--Product Valuation, Subpart 
A--General Provisions and Definitions

1. Definitions (Sec.  1206.20)
    In this final rule, ONRR consolidated the definitions from Federal 
oil (Sec.  1206.101), Federal gas (Sec.  1206.151), Federal coal (Sec.  
1206.251), and Indian coal (Sec.  1206.451). ONRR consolidated the 
existing definitions for these products to provide greater clarity and 
to eliminate redundancy. ONRR received comments on some of the modified 
definitions, which we discuss below.
    Area: See discussion in this preamble under Sec.  1206.105 
regarding the definition of the term ``area.''
    Coal Cooperatives: ONRR added a new definition of the term ``coal 
cooperatives'' that defines formal or informal organizations of 
companies or other entities sharing in a common interest to produce and 
market coal or coal-based products, the latter generally being 
electricity.
    Public Comment: One commenter argued that defining a coal 
cooperative was unnecessary. The commenter suggested that contracts are 
either arm's-length or non-arm's-length and that it does not matter if 
affiliated parties are part of a corporation or an ONRR-defined 
cooperative.
    ONRR Response: We seek a clear, consistent, and repeatable standard 
for valuing coal at its true market value. Coal cooperatives are formal 
or informal organizations of companies or other entities sharing in a 
common interest to produce and market coal or coal-based products, the 
latter generally being electricity. The services and benefits that coal 
cooperatives provide include, but are not limited to, manufacturing, 
selling, sampling, storing, supplying, permitting, transporting, 
marketing, or other logistic services. The relationship between a coal 
cooperative's members is not one of ``opposing economic interests'' 
and, therefore, is not at arm's-length.
    If none of the members own 10 percent or more of the coal 
cooperative, the coal cooperative will not be an affiliate under the 
definitions in this rule found in Sec.  1206.20. Nevertheless, the 
relationship between the coal cooperative and its members, as well as 
between the coal cooperative's members, is not at arm's-length for 
valuation purposes because they lack opposing economic interests. 
Therefore, the lessee must base the value of its coal production on the 
first arm's-length sale price received for the coal or electricity. We 
retained the term ``coal cooperative,'' but, in light of the

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comment that we received, we changed the proposed definition.
    Gathering: In this final rule, any movement of bulk production from 
the wellhead to a platform offshore is gathering and not 
transportation. ONRR changed the definition of the term ``gathering'' 
and added paragraph (a)(1)(ii) in Sec. Sec.  1206.110 and 1206.152 to 
rescind the May 20, 1999, ``Guidance for Determining Transportation 
Allowances for Production from Leases in Water Depths Greater Than 200 
Meters'' (Deep Water Policy). The Deep Water Policy allowed lessees to 
deduct certain costs associated with moving bulk production from the 
seafloor to the first platform.
    Public Comment: ONRR received several comments from industry and 
industry trade groups opposing our proposal to rescind the Deep Water 
Policy. Generally, the commenters opposed the categorical exclusion of 
subsea movement costs prior to the first platform as a transportation 
allowance. The commenters argued that such a determination was 
arbitrary and capricious. The commenters stated that rescinding the 
Deep Water Policy penalizes the development of innovative technologies 
that minimize surface facilities, reduce environmental risks, and 
increase ultimate recovery. Commenters stated that ONRR previously 
identified the movement of bulk production to the first platform as a 
valid transportation deduction and argue that we are now failing to 
provide sufficient justification to warrant rescinding the Deep Water 
Policy.
    ONRR received comments from public interest groups and a State 
supporting the removal of the Deep Water Policy. These commenters 
argued that the Deep Water Policy was inconsistent with ONRR's 
definition of gathering, and rescinding the policy will cure improper 
deductions of subsea gathering costs. In addition, the commenters 
believe that the proposed change will assure a fair market value for 
production while also reducing administrative costs for the oil and gas 
industry.
    ONRR Response: The former Minerals Management Service intended for 
the Deep Water Policy to incentivize deep water leasing by allowing 
lessees to deduct broader transportation costs than the regulations 
allowed. ONRR concluded that the Deep Water Policy has served its 
purpose and is no longer necessary. The regulations still allow 
offshore lessees to deduct considerable transportation costs to move 
oil and gas from the offshore platform to onshore markets. Rescinding 
this policy clarifies the meaning of gathering, which, in turn, 
provides a more consistent and reliable application of the regulations.
    Public Comment: ONRR received comments stating it understated the 
cost estimate of the impact to industry from removing the Deep Water 
Policy. The commenters claim the cost of removing the Deep Water Policy 
is much higher than ONRR's estimated $17.4 to $23.6 million total 
annual loss to all of industry.
    ONRR Response: ONRR does not agree. ONRR estimated the costs to 
industry using actual costs industry provided to ONRR during audits of 
the subsea gathering pipelines. ONRR used this data to estimate a per 
mile cost for subsea gathering pipelines. ONRR then used this per mile 
cost to calculate the total burden on industry associated with 
eliminating the Deep Water Policy. ONRR stands by its analysis.
    Misconduct: ONRR added a new definition for the term 
``misconduct.'' This new definition will apply to--and in conjunction 
with the--default provision. Misconduct, in this subpart, is different 
than--and in addition to--any violations subject to civil penalties 
under the Federal Oil and Gas Royalty Management Act of 1982 (FOGRMA), 
30 U.S.C. 1719, and its implementing regulations in 30 CFR part 1241. 
Behavior that constitutes misconduct under part 1206 does not need to 
be willful, knowing, voluntary, or intentional. This is a valuation 
mechanism, not an enforcement tool.
    Public Comment: Industry claims that the definition of misconduct 
is overly broad and argues that any common understanding of misconduct 
implies an element of intentional wrongdoing. Industry fears that ONRR 
may expand the use of the term to include even minor occurrences, such 
as simple reporting errors.
    ONRR Response: According to Black's Law Dictionary, the term 
``misconduct'' is ``any failure to perform a duty owed to the United 
States under a statute, regulation, or lease, or unlawful or improper 
behavior, regardless of the mental state of the lessee or any 
individual employed by, or associated with, the lessee.'' Consistent 
with this definition, this final rule does not require behavior to be 
willful, knowing, voluntary, or intentional to constitute misconduct. 
We only intend to use this definition of the term ``misconduct'' for 
valuation purposes, not for imposing penalties. Thus, no intent is 
required. Moreover, FOGRMA does not mandate a particular mental state 
for a lessee's obligation to correctly report, account for, and pay 
royalties for purposes of royalty valuation. For example, under this 
final rule, if we determine that you improperly calculated the value of 
your gas due to misconduct, we will calculate the value of your gas 
under Sec.  1206.144. However, if we determine that the misconduct was 
knowing or willful, we may pursue civil penalties under 30 CFR part 
1241.

B. Specific Comments on 30 CFR Part 1206--Product Valuation, Subpart 
C--Federal Oil

1. Calculating Royalty Value for Oil Sold Under an Arm's-Length 
Contract (Sec.  1206.101)
    Default: ONRR added that the value in this paragraph does not apply 
if we decide to value your oil under its new default valuation 
provision, which allows us to value your oil production under Sec.  
1206.105 or any other provision in this subpart. We also added that we 
may decide a lessee's oil value under the default valuation provision 
if the lessee fails to make the election in this paragraph related to 
exchange agreements.
    Public Comment: Almost unanimously, industry commenters object to 
the use of ONRR's default provision for oil. Industry comments 
highlight the following concerns: ``standardless'' ONRR discretion, 
second-guessing of arm's-length contracts and other lessee valuations, 
and a denial of lessees' ability to deduct all appropriate costs to 
reflect value at the lease. Several industry commenters argued against 
ONRR's ability to determine royalty value when a lessee or designee 
sells oil or gas for ten percent less than the lowest reasonable 
measures of market value. The industry commenters claim that different 
companies can negotiate better prices than others based on size and 
bargaining power.
    Several industry trade groups stated that it is not clear which 
offices (audit and compliance, enforcement, valuation, etc.) within 
ONRR have the ability to invoke the default provision and question 
whether there would be consistency in its application. These industry 
commenters also believe that the default provision (1) does not allow 
ONRR to honor arm's-length contracts and gross proceeds as the basis of 
valuation as in the past; (2) lacks specific criteria for determining 
what is reasonable valuation; (3) ONRR should not use it for simple 
reporting errors; and (4) is burdensome, an overreach of valuation 
authority, and creates uncertainty. Several industry trade groups add 
that the proposed rule offers little more than ``raw ipse dixit'' for 
promulgating its default provision and how ONRR intends to use it.

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    Several public interest groups suggested that the default provision 
should be mandatory and not discretionary. The consolidated comments 
from the State and Tribal Royalty Audit Committee (STRAC) provide that 
the State or Tribe must grant approval if ONRR applies the default 
provision in their jurisdiction.
    ONRR Response: ONRR disagrees with the commenters' statements that 
the default provision is a radical departure from our previous 
valuation policy. The regulatory changes do not alter the underlying 
principles of the previous regulations. For example, nothing in this 
final rule changes the Department's requirement that, for purposes of 
determining royalty, the value of crude oil produced from Federal 
leases is determined at or near the lease. And nothing in this final 
rule changes the fact that gross proceeds from arm's-length contracts 
are the best indication of market value.
    The default provision addresses valuation situations where 
circumstances result in the Secretary of the Interior's (Secretary) 
inability to reasonably determine the correct value of production. Such 
circumstances include, but are not limited to, the lessee's failure to 
provide documents, the lessee's misconduct, the lessee's breach of the 
duty to market, or any other situation that significantly compromises 
the Secretary's ability to reasonably determine the correct value. The 
mineral statutes and lease terms give the Secretary the authority and 
considerable discretion to establish the reasonable value of production 
by using a variety of discretionary factors and any other information 
that the Secretary determines is relevant. The default provision simply 
codifies the Secretary's authority to determine the value of production 
for royalty purposes and specifically enumerates when, where, and how 
the Secretary will use that discretion.
    Under this final rule, ONRR will continue the same treatment of 
arm's-length contracts as we have historically. We have never tacitly 
accepted values received under arm's-length contracts. We analyze all 
types of sales contracts in our reviews in order to validate proper 
value and deductions.
    Some commenters contend that ONRR did not perform an adequate 
economic analysis in assigning a royalty impact to invoking the default 
provision. We disagree and emphasize, again, that we anticipate using 
the default provision only in very specific cases where we cannot 
determine proper royalty values through standard procedures. Moreover, 
the royalty impact will be relatively small because the default 
provision will always establish a reasonable value of production using 
market-based transaction data, which has always been the basis for our 
royalty valuation rules.
    ONRR considers a lessee's refusal to provide requested documents to 
be a failure to permit an audit that is, and will continue to be, 
subject to civil penalties. ONRR's choice to invoke the default 
provision will not impact the lessee's obligation to provide documents 
or ONRR's ability to assess civil penalties for failure to permit an 
audit.
    Some commenters stated that it is not clear which offices within 
ONRR will apply the default provision and, if they did, what valuation 
criteria they would employ. We anticipate that, in most cases, we will 
use the default provision during the course of an audit. And, as we 
stated, the criteria that we would use to establish a royalty value is 
the same basic criteria upon which we base all royalty values. We list 
these criteria in Sec.  1206.105(a)-(f). Specifically, we may consider 
the value of like-quality oil in the same field or nearby fields or 
areas; the value of like-quality oil from the same plant or area; 
public sources of price or market information that we deem to be 
reliable; information available and reported to us, including, but not 
limited to, on the Report of Sales and Royalty Remittance (Form ONRR-
2014) and the Oil and Gas Operations Report (Form ONRR-4054); costs of 
transportation, if we determine that they are applicable; or any 
information that we deem relevant regarding the particular lease 
operation or the salability of the oil.
    Some industry commenters expressed concerns over their ability to 
challenge our use of the default provision. Industry's concerns are 
unwarranted because a company may appeal an order, including an order 
wherein we used the default provision to determine royalty value. 
Appeal rights under 30 CFR part 1290 will not change under this final 
rule.
    We disagree with those commenters who sought to make the default 
provision mandatory. We reiterate that we intend to use the default 
provision only in specific cases where conventional valuation 
procedures have not worked to establish a value for royalty purposes. 
We have the authority to use the default provision on behalf of the 
Secretary and as part of our delegated or cooperative agreements. We 
will work with STRAC to determine the royalty value of production that 
occurs in an affected State or on Tribal lands.
2. Calculating Royalty Value for Oil Not Sold Under an Arm's-Length 
Contract (Sec.  1206.102)
    Default: ONRR added a default valuation provision that allows us to 
value your oil production under Sec.  1206.105 or any other provision 
in this subpart. We addressed comments pertaining to the ``Default 
Provision'' paragraph, which we detail in Sec.  1206.101, in this 
Preamble.
3. Determination of Correct Royalty Payments (Sec.  1206.104)
    Default: ONRR added a default valuation provision that allows us to 
value your oil production under Sec.  1206.105 or any other provision 
in this subpart. We addressed comments pertaining to the ``Default 
Provision'' paragraph, which we detail in Sec.  1206.101, in this 
Preamble.
    Misconduct: ONRR added a new definition for the term 
``misconduct.'' We addressed comments pertaining to this definition, 
which we detail in Sec.  1206.20, in this Preamble.
    Unreasonably high transportation cost: ONRR added a default 
provision allowing us to determine your transportation allowance under 
Sec.  1206.105 if (1) there is misconduct by or between the contracting 
parties; (2) the total consideration that you or your affiliate pays 
under an arm's-length contract does not reflect the reasonable cost of 
transportation because you breached a duty to market oil for the mutual 
benefit of the lessee and the lessor by transporting oil at a cost that 
is unreasonably high; or (3) ONRR cannot determine if you properly 
calculated a transportation allowance for any reason. We addressed the 
default provision in detail in Sec.  1206.101.
    Public Comment: Many of the comments from industry and industry 
trade groups regarding our potential use of the default provision as it 
relates to the transportation of oil mirror those put forth for 
determining the value of oil. Commenters believe that our use of a 10-
percent variance above the highest reasonable measure of transportation 
standard is arbitrary, capricious, and unnecessary. Some comments 
representing States' interests, however, believe that ONRR should 
include stronger regulatory language requiring us to use the default 
method when the 10-percent variance is reached.
    ONRR Response: The default provision is an accommodating and 
necessary valuation tool that allows the Secretary to determine the 
correct amount of transportation deductions for oil. The 10-percent 
variance that we may use in our analysis of

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transportation transactions is nothing more than a tolerance to help 
determine a proper transportation allowance. In past and current 
compliance reviews and audit procedures, we have always used tolerances 
to reflect what is reasonable in any given market at any given time. 
Our use of the default provision under the final valuation regulations 
is a continuation of current practice. We will continue to determine 
transportation costs that industry incurs on their own merits based on 
reasonable actual costs allowable under the regulations.
    Written contracts: In this final rule, a lessee or its affiliate 
must have all of its contracts, contract revisions, or amendments in 
writing and signed by all the parties to those contracts, revisions, or 
amendments. Where the lessee does not have a written contract, ONRR may 
use the default provision to determine value.
    Public Comment: We received multiple comments on the rule's new 
provision stating that we will determine transportation allowances 
under Sec.  1206.105 if lessees do not have a written contract. The 
commenters generally disagreed with our requirement that all contracts 
be in writing because such a requirement is inconsistent with industry 
contracting procedures. Commenters also noted that contracts that are 
not in writing are still enforceable and that ONRR's definition of a 
contract in Sec.  1206.20 includes oral contracts that are legally 
enforceable.
    ONRR Response: FOGRMA requires the Secretary to ``establish a 
comprehensive inspection, collection and fiscal and production 
accounting and auditing system to provide the capability to accurately 
determine oil and gas royalties . . . and to collect and account for 
such amounts in a timely manner.'' 30 U.S.C. 1711(a). FOGRMA also 
requires lessees to provide ``any information the Secretary, by rule, 
may reasonably require'' 30 U.S.C. 1703(a). Since adopting the 
regulations in 1988, ONRR has required lessees to value their oil and 
gas production based on the gross proceeds accruing to the lessees for 
the sale of that oil and gas. These gross proceeds include deductions 
for the lessees' reasonable and actual costs of transportation. When 
lessees calculate their gross proceeds that include arm's-length sales 
and arm's-length transportation costs, the lessees must use the terms 
of those arm's-length contracts to calculate their gross proceeds. We 
have the responsibility of auditing gross proceeds in order to ensure 
that they reflect the total consideration actually transferred, either 
directly or indirectly, from the buyer to the seller. Through this 
auditing process, we have found it difficult to verify the accuracy of 
lessees' royalty payments when the lessees enter into oral contracts.
    This final rule's requirement that all arm's-length contracts be in 
writing is a logical evolution of our previous regulations. Section 
1207.5 requires lessees to commit oral contracts to written form and 
keep them as records. And the previous rules required arm's-length 
sales contract revisions and amendments to be in writing and signed by 
all parties. For more information about this, see Sec. Sec.  
1206.153(j), 1206.52(d)(2), 1206.102(e)(2)(ii) (requiring any amendment 
or revision to arm's-length purchase prices for oil to be in writing 
and signed by all parties in the agreement). By requiring fully-
executed arm's-length contracts, we no longer rely just on the lessee's 
written documentation outlining the terms of oral contracts. This 
guarantees that we can verify that the lessee's gross proceeds 
calculations are correct and include all consideration that you 
documented in the contract.
    One commenter provided case law indicating that contracts do not 
have to be in writing to be enforceable. This comment, however, ignores 
the burden that we bear to verify and accurately determine that the 
lessees' royalty payments are correct. We must audit and evaluate 
countless contracts in order to verify royalty payments for Federal and 
Indian lands. Tracking email exchanges, letters, or other confirmations 
creates inefficiencies in our accounting and auditing systems, which 
limits our ability to fulfill FOGRMA's mandate to verify and account 
for royalty payments.
4. Determination of the Oil Value for Royalty Purposes (Sec.  1206.105)
    Default: ONRR added a default valuation provision that allows us to 
value your oil production under Sec.  1206.105 or any other provision 
in this subpart. We addressed comments pertaining to the ``Default 
Provision'' paragraph, which we detail in Sec.  1206.101, in this 
Preamble.
    Area: ONRR removes the phrase ``legal characteristics'' from the 
definition of the term ``area.''
    Public Comment: We received comments from industry that they oppose 
the modified definition of ``area.'' The commenters believe that the 
new definition would ``revise the definition of area in a manner that 
overtly changes the breadth of the marketable condition rule.'' The 
commenters rely on the Interior Board of Land Appeals' (IBLA) decision 
in Encana Oil & Gas (USA), Inc., 185 IBLA 133 (2014) (Encana) as an 
example to illustrate how the definition of area has expanded over 
time. One commenter stated, ``In short, the ONRR's proposed revision of 
the definition of `area' will result in inconsistent and uncertain 
marketable condition determinations.''
    ONRR Response: We modified the definition of the term ``area'' to 
clarify that an area does not have boundaries or names. The commenter's 
concern, however, is misplaced because the definition of the term 
``marketable condition'' remains the same. And, as the commenter points 
out, case law aids in defining the term ``marketable condition.'' We 
cite Encana as the basis for this, where the finding was that a ``sales 
contract typical for the field or area'' reasonably refers to the 
contracts that are typical in the field or area into which the gas is 
actually sold, which may or may not be the field or area where the gas 
is produced. Because we do not change the definition of the term 
``marketable condition'' and our modification to the term ``area'' does 
not alter the precedent set out in Encana and other cases interpreting 
the definition of the term ``marketable condition,'' we are retaining 
the definition of the term ``area'' as we have proposed.
5. Valuation Determination Requests (Sec.  1206.108)
    Guidance and Determinations: Under paragraph (a), a lessee may 
request a valuation determination or guidance from ONRR regarding any 
oil produced. Paragraph (a) provides that the lessee's request for a 
determination must (1) be in writing; (2) identify all leases involved; 
(3) identify all interest owners in the leases; (4) identify the 
operator(s) for those leases; and (5) explain all relevant facts. In 
addition, under paragraph (a), a lessee must provide (1) all relevant 
documents; (2) its analysis of the issue(s); (3) citations to all 
relevant precedents (including adverse precedents); and (4) its 
proposed valuation method.
    In response to a lessee's request for a determination, ONRR may (1) 
decide that we will issue guidance; (2) inform the lessee in writing 
that we will not provide a determination or guidance; or (3) request 
that the Assistant Secretary for Policy, Management and Budget (ASPMB) 
issue a determination.
    Paragraphs (b)(3)(i) and (ii) identify situations in which ONRR and 
the Assistant Secretary typically do not provide a determination or 
guidance, including, but not limited to, requests for determinations or 
guidance on hypothetical situations and matters that

[[Page 43343]]

are the subject of pending litigation or administrative appeals.
    Under paragraph (c)(1), a determination that the ASPMB signs binds 
both the lessee and ONRR unless the Assistant Secretary modifies or 
rescinds the determination.
    Public Comment: Industry raised three concerns regarding valuation 
guidance and determinations. First, commenters were concerned that ONRR 
will require excessive data and legal analysis in order for industry to 
receive valuation guidance or a determination. Second, commenters 
suggest that ONRR add language specifying that, if a lessee receives 
non-binding guidance and then chooses not to follow that guidance, ONRR 
would not pursue civil penalties based on that guidance. Third, 
commenters suggest that ONRR provide only appealable determinations and 
binding determinations that the ASPMB signs rather than non-appealable, 
non-binding guidance.
    ONRR Response: In this final rule, we retained the language 
requiring industry to provide specified information to receive a 
valuation determination. However, we recognize that, where a lessee 
requests valuation guidance rather than a determination, less 
information may suffice because requests for guidance are not requests 
for our approval of a valuation method.
    Under 30 CFR part 1241, ONRR may issue a notice of non-compliance 
if you fail to comply with any requirement of a statute, regulation, 
order, or terms of a lease. Because this language clearly establishes 
when we may issue a notice of non-compliance, it is not necessary to 
add language specifically addressing civil penalties for failure to 
follow non-binding guidance.
    We provide guidance in cases where industry has a question 
regarding the application of statutes and regulations to a particular 
set of circumstances. This guidance provides industry with an 
opportunity to ask questions about their particular circumstances 
without proposing a valuation method. Requests for determinations, on 
the other hand, are proposals from industry for ONRR approval of a 
specific valuation method. By providing a guidance option, we can 
answer questions more quickly and without requiring industry to submit 
all of the information that we would require for a determination. 
Industry may always request a binding determination.
6. General Transportation Allowance Requirements (Sec.  1206.110)
    In this final rule, we re-ordered paragraph (a) to add clarity.
    Subsea gathering: In paragraph (a), we added a new provision 
stating that you may not take a transportation allowance for the 
movement of oil produced on the Outer Continental Shelf (OCS) from the 
wellhead to the first platform. This addition, along with the changes 
to the definition of gathering, rescinds the Deep Water Policy. We 
addressed comments pertaining to this issue in Sec.  1206.20.
    Fifty-percent allowance cap: In this final rule, we eliminated the 
regulation allowing us to approve transportation allowances in excess 
of 50 percent of the value of a lessee's oil production. Under this 
final rule, any prior approvals terminate on the date when this rule 
becomes final.
    Public Comment: We received comments from States and public 
interest groups supporting the elimination of ONRR's authority to 
approve transportation allowances in excess of the 50-percent allowance 
cap. However, the State commenters asserted that the 50-percent cap, 
itself, was too broad. The States suggested that we calculate allowance 
caps for each State and use a percentage based on the average 
transportation costs in each State over a ten-year period. The State 
commenters suggested that we update and post such percentages on our 
Web page.
    ONRR Response: At this time, we decline to implement the States' 
suggestion to reevaluate caps on transportation allowances as a whole. 
The 50-percent limitation is not the only check on the reasonableness 
of transportation costs. The 50-percent limitation supplements the 
requirement that a lessee's transportation costs be actual and 
reasonable. In this final rule, the limitation clause states that your 
transportation allowance may not exceed 50 percent of the oil value 
determined under Sec.  1206.101. This final rule defines the term 
``transportation allowance'' as a deduction in determining royalty 
value for reasonable, actual costs that the lessee incurs for moving 
oil to a point of sale or delivery off of the lease. The 50-percent 
limitation is a limit on the allowance--a lessee's reasonable, actual 
costs of transportation--and not a statement that any cost up to 50 
percent is reasonable. To find otherwise would allow a lessee to spend 
$100 on a repair that could have been performed for $10 and deduct the 
entirety of the expense against a $200 royalty obligation. Thus, the 
regulation, read as a whole, mitigates the States' concern.
    Public Comment: ONRR received several comments from industry and 
industry trade groups opposing the elimination of our authority to 
approve transportation allowances in excess of the 50-percent allowance 
cap. These commenters stated that the right to request approval to 
exceed the 50-percent limitation is necessary because its removal 
denies a lessee the ability to deduct all of its actual, reasonable, 
and necessary transportation costs when those costs exceed 50 percent.
    ONRR Response: The 50-percent limitation is a sufficient 
transportation allowance. The Mineral Leasing Act (MLA) requires 
lessees to pay royalties at 12\1/2\ percent in amount or value of 
production removed or sold from the leased lands. The Outer Continental 
Shelf Lands Act (OSCLA) requires a royalty of not less than 12\1/2\ 
percent in amount or value of production saved, removed, or sold from 
the leases. However, the MLA and OCSLA do not define the term 
``value,'' which gives the Secretary considerable discretion to define 
the term ``value.'' The regulations at 30 CFR part 1206 determine value 
and, under these regulations, the Secretary allowed deductions for 
transportation allowances. It is this discretion that provides an 
allowance, generally, which the Secretary now caps at 50 percent of the 
value of oil production.
    Public Comment: Several commenters take issue with ONRR terminating 
any approval that it previously issued for a lessee to exceed the 50-
percent limitation. The commenters believe that terminating prior 
approvals is ``retroactive.'' Thus, the commenters suggest that ONRR 
should allow such approval to expire on the expiration date set out in 
the approval.
    ONRR Response: We disagree with the commenters who claim that the 
proposed rule's termination of prior approvals to allow transportation 
allowances to exceed the value of a lessee's oil production is 
retroactive. In Reynolds v. United States, 292 U.S. 443, 449 (1934), 
the Supreme Court determined that ``a statute is not rendered 
retroactive merely because the facts or requisites upon which it's 
subsequent action depends, or some of them, are drawn from a time 
antecedent to the enactment.'' This means, as long as the new rule does 
not modify ``the past legal consequences of past actions,'' those rules 
are not improperly retroactive. Bowen v. Georgetown Univ. Hosp., 488 
U.S. 204, 219-20 (1988) (J. Scalia, concurring). Just because an 
agency's rule may ``upset[ ] expectations based on prior law'' does not 
mean the rule is retroactive. Mobile Relay Associates v. F.C.C., 457 
F.3d 1, 10-11 (D.C. Cir. 2006).

[[Page 43344]]

    While terminating prior approvals to exceed the 50-percent cap for 
transportation allowances may disappoint some lessee's expectations, 
the rule, itself, is not retroactive because it does not affect the 
legal consequences of the lessee's past actions. Prior to this final 
rule, under our approval, a lessee was able to deduct transportation 
allowances that were higher than 50 percent of the value of the 
lessee's oil production. The new rule does not hinder the lessee's 
ability to do so for past production months; however, for each 
production month after the effective date of this rule, a lessee will 
no longer be able to deduct over 50 percent of the value of its oil 
production as a transportation allowance. Thus, this final rule is 
entirely prospective and not, as the opposing comments suggest, 
retroactive.
    ONRR approved most requests to exceed the 50-percent cap on 
transportation allowances for a one-year period. Rarely, we approved 
them for a two-year period. In either case, the proposed rule put 
lessees on notice that we intended to remove such approvals.
    Public Comment: A few commenters also state that, because ONRR 
retained a similar provision in the new Indian oil valuation 
amendments, removing that provision here would be arbitrary.
    ONRR Response: While we retained the provision in the Indian oil 
valuation amendments, we have never received a request to exceed the 
50-percent limitation on transportation allowances for Indian oil. And, 
unlike with this rule, the purpose of the Indian oil valuation 
amendments was to implement recommendations from a negotiated 
rulemaking committee. Because the committee did not recommend a change, 
we retained this provision. We may revisit the issue of a cap on 
transportation allowances claimed on Indian oil at a later date.
    Eliminating transportation factors: Previously, ONRR allowed 
lessees to net transportation from their gross proceeds when the 
lessees' arm's-length contract reduced the price of the oil by a 
transportation factor. In this final rule, we eliminated this provision 
and, instead, require lessees to report such costs as a separate entry 
on Form ONRR-2014.
    Public Comment: ONRR received comments from industry, industry 
trade groups, and an individual commenter opposing the elimination of 
transportation factors. The commenters stated that, if ONRR eliminated 
transportation factors, it would result in numerous complications due 
to insufficient guidance.
    One industry trade group pointed out that ONRR does not define the 
term ``transportation factor'' in the proposed rule, and it is, 
therefore, unclear what is or is not a transportation factor. They 
suggest that, if ONRR pursues not allowing the netting of the 
transportation factor, ONRR needs to clearly define the term.
    The commenters also noted that lessees will have a difficult time 
discerning what a transportation factor is because the lessees do not 
incur the costs, their purchasers do. Therefore, the commenters claim 
that the detail of the costs is not readily available to lessees to 
accommodate reporting the costs separately as transportation 
allowances. One commenter stated that transportation factors may 
include multiple items, ``some of which may not be considered a 
transportation factor.''
    ONRR Response: In this final rule, lessees may deduct their 
reasonable actual costs of transportation. The burden lies with the 
lessees to support their reasonable actual costs of transportation. We 
have never defined the term ``transportation factor.'' Historically, we 
used the term ``transportation factor'' to identify the situation when 
a sales contract contains a provision to reduce the base price by costs 
that the purchaser incurred to move the production to a downstream 
location.
    These comments underscore why we eliminated transportation factors: 
To facilitate transparency, audits, and reviews. Eliminating factors 
ensures that transportation allowances are measurable and auditable 
because we can identify and audit transportation deductions when 
lessees report them separately from their sales price. When lessees 
report their sales value net of transportation, we cannot discern the 
transportation costs from the sales value. Moreover, the comment 
stating that transportation factors include multiple other items, 
including quality differences and services that may not be deductible 
from the royalty basis, shows the difficulty that we face in reviewing 
transportation factors as allowable transportation deductions. The 
factors may include bundled costs or may be a differential. Yet 
lessees, not ONRR, have the burden of identifying their allowable, 
reasonable, and actual costs of transportation. Eliminating 
transportation factors and requiring lessees to report transportation 
separately as allowances ensures that lessees meet that burden.
    Misconduct: ONRR added a new definition for the term 
``misconduct.'' We addressed comments pertaining to this issue, which 
we detail in Sec.  1206.20, in this Preamble.
    Default: ONRR addressed comments pertaining to the ``Default 
Provision'' paragraph, which we detail in Sec.  1206.101, in this 
Preamble.
    Unreasonably high transportation cost: ONRR addressed comments 
pertaining to this issue, which we detail in Sec.  1206.104, in this 
Preamble.
7. Determination of Transportation Allowances for Arm's-Length 
Transportation (Sec.  1206.111)
    Line fill: ONRR retains the provision allowing a lessee to include 
the costs of carrying line fill on its books as a component of arm's-
length transportation allowances. We deleted proposed Sec.  
1206.111(c)(9) and retained line fill as an allowable deduction in the 
final rule as the new Sec.  1206.111(b)(11). Because oil will only flow 
through a pipeline if that pipeline is filled with oil, some pipeline 
operators require that shippers (lessees) leave some of their oil in 
the pipeline. The shipper's oil that remains in the pipeline is, in 
effect, inventory that cannot be sold as long as the shipper uses the 
pipeline to transport its oil. In other cases, the pipeline operator 
owns the oil that fills the line and charges the shipper a cost at 
least equal to its capitalized costs as part of the arm's-length price 
or tariff. We proposed to eliminate this provision because we 
considered this to be a cost of marketing the oil, reasoning that line 
fill occurs after the royalty measurement point and is necessary in 
order for the pipeline operator to transport Federal oil production to 
downstream markets. We requested comments on whether line fill is a 
marketing cost.
    Public Comment: ONRR received several comments on line fill. 
Industry pointed out that, in the 2004 Federal Oil Valuation Rule, ONRR 
identified line fill as a cost of transportation. In that same 
rulemaking, ONRR also pointed out that they do not allow a lessee to 
deduct the costs of marketing. At that time, ONRR recognized that line 
fill is not a marketing cost. Industry believes that line fill is not a 
cost of marketing oil. Instead, industry believes that, in cases where 
the pipeline requires it to dedicate its oil to transport its oil, ONRR 
should permit the cost of carrying this inventory as an allowable 
transportation deduction.
    A public interest group supported the change and believes that the 
removal of this provision is in keeping with the overall goal of 
achieving a fair return for the taxpayer. One State agreed with ONRR's 
proposal, noting that line fill falls within a lessee's duty to market.

[[Page 43345]]

    ONRR Response: We agree with industry commenters that lessees may 
deduct their reasonable actual transportation costs. For those lessees 
who must provide production as line fill, we retained the provision 
that allows the cost of carrying on your books as inventory a volume of 
oil that you or your affiliate, as the pipeline operator, maintain(s) 
in the line as line fill as an allowable transportation cost.
    Written contracts: We added a new provision that states that we 
will determine transportation allowances under Sec.  1206.105 if 
lessees do not have a written contract for the arm's-length 
transportation of oil. We addressed comments pertaining to this issue, 
which we detail in Sec.  1206.104, in this Preamble.
    Eliminating transportation factors: Previously, ONRR allowed 
lessees to net transportation from their gross proceeds when the 
lessees' arm's-length contract reduced the price of the oil by a 
transportation factor. In this final rule, we eliminated this provision 
and, instead, require lessees to report such costs as a separate entry 
on Form ONRR-2014. We addressed comments pertaining to this issue, 
which we detail in Sec.  1206.110, in this Preamble.
8. Determination of Transportation Allowances for Non-Arm's-Length 
Transportation Contracts (Sec.  1206.112)
    Line fill: ONRR retains the provision that allows lessees to 
include the costs of carrying line fill on their books as a component 
of arm's-length transportation allowances. We deleted proposed Sec.  
1206.111(c)(9) and retained line fill as an allowable deduction in the 
final rule as the new Sec.  1206.112(c)(1)(v). We proposed to eliminate 
this provision because we considered this a cost of marketing the oil, 
reasoning that line fill occurs after the royalty measurement point and 
is necessary in order for the pipeline operator to transport Federal 
oil production to downstream markets. We requested comments on whether 
line fill is a marketing cost. We addressed comments pertaining to this 
issue, which we detail in Sec.  1206.110, in this Preamble.
    Pipeline losses: In this final rule, under paragraph (c)(2)(ii), 
ONRR eliminated the provision that allows lessees to deduct the costs 
of pipeline losses, both actual and theoretical, under non-arm's-length 
transportation situations.
    Public Comment: Multiple companies and industry trade groups 
opposed removing the provision to allow lessees with non-arm's-length 
transportation arrangements to deduct actual and theoretical losses, 
stating that losses are a real cost to lessees.
    A State commenter supported this change and suggested disallowing 
all losses, including line loss charges under arm's-length contracts. A 
public interest group supported this change, stating that this change 
will ensure that royalty value is based on oil actually removed from 
the lease without subsidizing losses occurring after the royalty 
measurement point.
    ONRR Response: Beginning with the May 5, 2004, Federal Oil 
Valuation Rule, we allowed lessees to deduct the costs of actual line 
losses in non-arm's-length oil transportation situations. Since that 
time, it has been difficult for lessees to demonstrate, and impractical 
for us to verify, that line losses in non-arm's-length or no-contract 
situations are valid and not the result of meter error or other 
difficult-to-measure causes.
    FOGRMA requires the Secretary to ``establish a comprehensive 
inspection, collection and fiscal and production accounting and 
auditing system to provide the capability to accurately determine oil 
and gas royalties . . . and to collect and account for such amounts in 
a timely manner'' (30 U.S.C. 1701(a)). Because we must account for all 
royalties and associated deductions and because we cannot properly 
verify deductions associated with losses in non-arm's-length 
situations, we retain the language from the proposed rule that lessees 
may not deduct any costs associated with actual or theoretical losses 
in non-arm's-length oil transportation situations. We will still allow 
lessees to deduct the actual costs of losses that they incur under 
arm's-length transportation agreements because the payment is a true 
out-of-pocket expense to the lessee.
    BBB bond rate: ONRR reduced the multiplier on any remaining 
undepreciated capital costs from 1.3 to 1.0 times the Standard & Poor's 
BBB bond rate. We moved this provision to Sec.  1206.112(i)(3).
    Public Comment: Several companies and industry trade groups opposed 
modifying the Standard & Poor's BBB bond rate multiplier. Commenters 
state that ONRR failed to sufficiently analyze rates of return for 
pipelines and should provide better support for its decision to reduce 
the multiplier to 1.0. A State supported reducing the multiplier, 
noting that market fluctuations impact transportation facilities less.
    ONRR Response: Modifying the Standard & Poor's BBB bond rate 
multiplier recognizes changes within the economy since 2005 (including 
lower interest rates) and creates consistency with other product 
valuation guidelines. This rate better reflects the cost of borrowing 
to finance capital expenditures involved in pipeline construction.
9. Adjustments and Transportation Allowances When Using NYMEX Prices or 
Alaska North Slope (ANS) Prices for Oil Royalty Value (Sec.  1206.113)
    Eliminating transportation factors: Previously, ONRR allowed 
lessees to net transportation from their gross proceeds when the 
lessees' arm's-length contract reduced the price of the oil by a 
transportation factor. In this final rule, we eliminated this provision 
and, instead, require lessees to report such costs as a separate entry 
on Form ONRR-2014. We addressed comments pertaining to this issue, 
which we detail in Sec.  1206.110, of this Preamble.
10. Reporting Requirements for Arm's-Length Transportation Contracts 
(Sec.  1206.115)
    Eliminating transportation factors: Eliminating transportation 
factors will require lessees to report any transportation costs 
embedded in an arm's-length contract as a separate line entry on Form 
ONRR-2014.
    Public Comment: ONRR received multiple comments indicating industry 
would suffer significant administrative burdens to extract, separate or 
``unbundle'' transportation costs from their arm's-length sales 
contracts. The commenters indicated that removing transportation 
factors will result in ``large scale contract review and major changes 
to accounting systems and processes.''
    ONRR Response: We recognize that eliminating transportation factors 
requires lessees to report their transportation costs embedded in an 
arm's-length contract separately as a transportation allowance, which 
may require changes in the lessees' reporting systems. However, 
removing transportation factors increases transparency and helps us 
verify that such costs are the reasonable and actual costs that lessees 
incur for transportation. Furthermore, as we mentioned previously, 
transportation factors may include multiple items embedded in arm's-
length sales contracts.

[[Page 43346]]

C. Specific Comments on 30 CFR Part 1206--Product Valuation, Subpart 
D--Federal Gas

1. Calculating Royalty Value for Unprocessed Gas Sold Under an Arm's-
Length or Non-Arm's-Length Contract (Sec.  1206.141)
    Dual accounting: Because we removed the dual accounting requirement 
under proposed Sec.  1206.151, we deleted paragraph (a)(3), which 
referenced it. We re-numbered proposed paragraph (a)(4) as (a)(3) in 
this final rule.
    First arm's-length sale: In this final rule, ONRR eliminated the 
non-arm's-length valuation benchmarks and requires lessees to value gas 
production based on how they sell their gas (such as using (1) the 
first arm's-length-sale prices, (2) optional index prices, or (3) 
volume weighted average of the values established under this paragraph 
for each contract for the sale of gas produced from that lease). Under 
Sec.  1206.141(b)(2), if you sell or transfer your Federal gas 
production to your affiliate, or some other person at less than arm's-
length, and that person or their affiliate then sells the gas at arm's-
length, you will base your royalty value on the other person's (or 
their affiliate's) gross proceeds under the first arm's-length 
contract. However, two exceptions apply: (1) Lessees may elect to use 
the index-pricing option under Sec.  1206.141(c) of this section, or 
(2) we decide to value your gas under the default valuation provision 
in Sec.  1206.144.
    Public Comment: A State and a public interest group supported 
ONRR's proposal to require lessees to value non-arm's-length 
dispositions of gas production based on the first arm's-length sale 
rather than the gas valuation benchmarks.
    Industry trade groups suggested that ONRR reword the regulatory 
language under subsection (b) for clarity. The commenters were 
concerned that the word ``may'' and the words ``or another person,'' 
could lead to misinterpretation of this rule's intent.
    ONRR Response: We recognize that the wording under proposed Sec.  
1206.141(b) caused some confusion and reworded this paragraph in the 
final rule.
    Public Comment: Several industry commenters asserted that tracing 
their affiliates' arm's-length gross proceeds is complicated and 
burdensome. One industry trade group remarked that Sec.  1206.141(b) 
does not address costs unique to marketing and transporting Compressed 
Natural Gas (CNG) and Liquefied Natural Gas (LNG), where the first 
arm's-length sale may be at a distant international market.
    ONRR Response: The values established in arm's-length transactions 
are the best indication of market value. We recognize that changes in 
industry and the marketplace may make it difficult for a lessee to 
value its gas using the benchmarks. To address these difficulties, we 
eliminated the benchmarks in order to provide early certainty and gave 
lessees with non-arm's-length sales the option to value gas based on 
the first arm's-length sale or index prices.
    Index-based valuation option: ONRR added a new paragraph (c) 
containing an index-price valuation method that a lessee may elect to 
use in lieu of valuing its gas under proposed paragraphs (b)(2) and 
(b)(3). ONRR based the method on publicly-available index prices, less 
a specified deduction to account for processing and transportation 
costs. This valuation method also applies to certain ``no contract'' 
situations that we describe under paragraph (e).
    The index-based option provides a lessee with a valuation option 
that is simple, certain, and avoids the requirements to unbundle fees 
and ``trace'' production. This is applicable when there are numerous 
non-arm's-length sales prior to an arm's-length sale. Under paragraph 
(c), the lessee may choose to value its gas only in an area that has an 
active index pricing point published in an ONRR-approved publication. 
The lessee may elect to value its gas under this paragraph, making that 
election binding on the lessee for two years. ONRR will post a list of 
approved publications at www.onrr.gov.
    In this final rule, under paragraph (c), there are three possible 
scenarios for establishing the index-price point. The first scenario is 
when you can only transport gas to one index pricing point published in 
an ONRR-approved publication. In this scenario, your value for royalty 
purposes is based on that index pricing point.
    The second scenario is when you can physically transport gas to 
more than one index pricing point. In this scenario, you must base your 
value for royalty purposes on the highest index pricing point to which 
your gas could flow. For example, assume that you have a lease in the 
West Delta area of the Gulf of Mexico, and your lease is physically 
connected by a pipeline to the Mississippi Canyon Pipeline. In this 
case, your gas is physically capable of flowing to the Toca Plant 
(through the Southern Natural Gas Pipeline), the Yscloskey Plant 
(through the Tennessee Gas Pipeline), or the Venice Plant. This means 
that you have multiple index pricing points to which your gas can 
physically flow. Also, assume that the highest reported monthly bidweek 
price among the multiple index pricing points is the Tennessee Gas 500 
Leg Price at the tailgate of the Yscloskey Plant. Finally, assume that 
you cannot flow your gas through the Tennessee Gas Pipeline (to the 
Yscloskey Plant) because all available capacity on that pipeline is 
under contract to other persons, and the pipeline has no capacity 
available to you for the production month--in other words, it is 
constrained. In this example, you would use the highest reported 
monthly bidweek price at the tailgate of the Yscloskey Plant as the 
value under this paragraph even though your gas did not flow to that 
index pricing point during that production month.
    The third scenario is when there are multiple sequential pricing 
points on a pipeline through which you could transport your gas. In 
this scenario, you must base your value for royalty purposes on the 
first index pricing point after your gas enters that pipeline.
    Under paragraph (c), the lessee can only use an index pricing point 
if it could physically transport its gas to that index pricing point 
because there is a pipeline or series of pipelines that physically 
connect to the lease and flow from the lease to the index pricing 
point. We will exclude the use of index pricing points where a lessee 
cannot sell its gas.
    If the lessee can transport its gas to only one index pricing 
point, the lessee must base its value under paragraph (c)(1)(i) on the 
highest reported monthly bidweek price for that index pricing point in 
the ONRR-approved publication for the production month. If the lessee 
can transport its gas to more than one index pricing point, the lessee 
must base its value under paragraph (c)(1)(ii) on the highest reported 
monthly bidweek price for the index pricing points to which the lessee 
could transport its gas in the ONRR-approved publication for the 
production month. However, under paragraph (c)(1)(iii), if there are 
sequential index pricing points on a pipeline, the lessee must base its 
value on the first index pricing point at or after the lessee's gas 
enters the pipeline.
    We recognize that index pricing points are normally located off of 
the lease and, frequently, are at lengthy distances from the lease. 
Thus, under paragraph (c)(1)(iv), we allow a lessee to reduce the 
highest reported monthly bidweek price by a set amount to account for 
transportation costs that a lessee would incur to move the gas from

[[Page 43347]]

the lease to an applicable index pricing point. We will allow a lessee 
to reduce the highest reported monthly bidweek prices by 5 percent for 
sales from the OCS Gulf of Mexico and by 10 percent for sales from all 
other areas, but not by less than 10 cents per MMBtu or more than 30 
cents per MMBtu.
    Paragraph (c)(1)(v) states that, after you select an ONRR-approved 
publication available at www.onrr.gov, you may not select a different 
publication more often than once every two years. We will also, under 
paragraph (c)(1)(vi), exclude individual index prices from this option 
if we determine that the index price does not accurately reflect the 
value of production. We will post a list of excluded index pricing 
points at www.onrr.gov.
    Paragraph (c)(2) explains that you may not take any other 
deductions from the value calculated under this paragraph (c) because 
you would already receive a reduction for transportation under 
paragraph (c)(1)(iv).
    Public Comment: Public interest groups supported the changes as an 
overall effort to provide greater clarity and transparency to the 
valuation process. A State commenter and STRAC opposed using an index-
based option for reasons identified below.
    While industry commenters supported the idea of an index-based 
method, they did not support the method as proposed. Industry 
commenters explained that the proposed index-based method results in a 
value so far above what is reasonable that few lessees would choose to 
use it. Commenters argued that using the highest bidweek price results 
in an inflated value for royalty purposes and is neither reasonable nor 
justified.
    ONRR Response: The value under an index-based valuation option is 
reasonable and justified because of the benefits that it affords to the 
lessee. Lessees have the burden of showing that none of the costs that 
they incur and deduct are costs to place their gas production in 
marketable condition. Burlington Res. Oil & Gas Co. LP v. U.S. Dep't of 
the Interior, No. 13-CV-0678-CVE-TLW, 2014 WL 3721210, at *12 (N.D. 
Okla. July 24, 2014). This burden includes separating or ``unbundling'' 
costs associated with putting production in marketable condition as 
discussed in Burlington. If the lessee chooses to use the index-based 
option, it will relieve the lessee of those responsibilities. While 
this method benefits lessees, it must also protect the interests of the 
Federal lessor. The index-based valuation method does just that.
    Public Comment: Industry commenters argued that the requirement to 
use the highest index price at a pricing point to which a lessee's gas 
could flow effectively requires a lessee to pay royalty on the highest 
theoretically obtainable price, even though that price is not, in fact, 
obtainable. They explained that ONRR cites no authority or 
justification for this proposed standard. Instead, the commenters 
suggested that the rule require a lessee to base the value of its gas 
on the index where the lessee's gas actually flowed.
    ONRR Response: This provision protects the interests of the Federal 
lessor, while also simplifying the royalty reporting process for 
industry. If this rule required a lessee to calculate royalty on the 
basis of the index pricing point(s) to which the gas did flow, we would 
require companies to trace production, potentially through a series of 
affiliated transactions, and determine what volumes of gas flowed to 
which index pricing points. This increases the burden for both industry 
and us. We retained this provision in the final rule because it is 
consistent with the administrative simplicity that the index-based 
method seeks to achieve.
    Public Comment: Industry commenters stated that the fixed 
adjustments for transportation are too low and do not reflect current 
gas transportation rates.
    ONRR Response: We analyzed transportation rate data, as we 
discussed in the Procedural Matters section, and determined that the 
rates, as proposed, are a reasonable reduction to the index price.
    Public Comment: A State commenter expressed concern over the 
potential manipulation of prices, providing that commercial price 
bulletins are subject to manipulation and, indeed, have been 
manipulated.
    ONRR Response: We recognize the State's concern, but the index-
based valuation method protects the Federal and State royalty interests 
for the following reasons: (1) Federal Energy Regulatory Commission 
(FERC) must approve pricing publications, and the publication companies 
also have protections to prevent and discourage price manipulation; (2) 
we have the discretion to disallow the use of price points that are not 
liquid and are more subject to manipulation; (3) we designed the index-
based valuation method to generally result in a value higher than gross 
proceeds because of the simplicity and clarity that it affords to 
lessees; and (4) index prices are a trusted measure of value in the gas 
sales industry and the basis for many arm's-length sales contracts.
    Public Comment: STRAC requested that (1) States have the option to 
``opt in'' for index-based valuation (similar to Indian Tribes for 
Indian gas valuation); (2) there be some ``price testing'' on the use 
of these index prices; and (3) there be a ``true-up'' to ensure that 
the index-based valuation was higher than a company's gross proceeds.
    ONRR Response: The index-based value protects both Federal and 
State interests. We analyzed Form ONRR-2014 royalty data and compared 
it to index prices for the years 2007 through 2010. We found that the 
index price was consistently higher than the average value received 
under gross proceeds. A rule that allows each State to choose to opt in 
or requires an annual true-up negates the administrative simplicity and 
clarity that we intend for the index-based option.
    Public Comment: One industry trade group commented that ONRR's 
proposal would burden small operators with the added expense required 
to subscribe to an industry price publication, which they believe is an 
unnecessary cost.
    ONRR Response: We note that there is, potentially, an additional 
expense if a company values their gas under the index-based option. We 
consider this potential additional expense to be a cost of doing 
business associated with properly reporting and paying Federal 
royalties.
    Public Comment: Industry commenters strongly urged that the index-
based option be available to value arms-length transactions. These 
commenters noted that the 1995-1996 Federal Gas Valuation Negotiated 
Rulemaking Committee recommended the same. One industry trade group 
specifically stated, ``ONRR should afford Federal gas lessees the 
option of using an index-pricing option to value royalties under arm's-
length sales to avoid the burden of chasing gross proceeds to distant 
markets and to obviate the unnecessary step of creating an affiliate 
simply for the purpose of affording the lessee the regulatory option of 
choosing index pricing.''
    ONRR Response: Gross proceeds under valid arm's-length transactions 
are the best measure of value. The use of index prices as one option 
for valuing non-arm's-length transactions is appropriate because of the 
complex nature of transactions between affiliates and the potential 
administrative burden of pursuing and supporting the value under the 
first arm's-length sale. In this final rule, we will not expand the 
index-based option to arm's-length sales.

[[Page 43348]]

    No-sale situations: Paragraph (d)(1) provides that, if you have no 
written contract or no sale of gas subject to this section, and there 
is an index pricing point for the gas, then you must value your gas 
under the index-pricing provisions of paragraph (c) of this section 
unless ONRR values your gas under Sec.  1206.144. We intended this 
provision to address situations including, but not limited to, when (1) 
the lessee sells its gas to an affiliate, and the affiliate uses the 
gas in its facility; (2) the lessee sells its gas to an affiliate, the 
affiliate resells the gas to another affiliate of either the lessee or 
itself, and that affiliate uses the gas in its facility; (3) the lessee 
uses the gas as fuel for its other leases in the field or area; or (4) 
the lessee delivers gas to another person as payment for an overriding 
royalty interest that the other person holds.
    Public Comment: A commenter noted that lessees do not sell gas used 
or lost along the pipeline and may currently value those volumes under 
the benchmark valuation regulations. The commenter stated that, 
previously, using the price that the lessee received for the gas that 
it sold as the basis to value its gas used or lost along the pipeline 
was a much more certain method of valuing gas, which also satisfied 
benchmark two. Instead, the commenter argues that the rule requires the 
lessee to submit a proposed valuation method and be subject to having 
to make retroactive changes if ONRR does not accept the proposed 
method. The commenter argued that it was unfair to require lessees who 
cannot otherwise use the index-based option (those making arm's-length 
sales) to have to use the index-based pricing to value gas used or lost 
along a pipeline and adds unnecessary complexity.
    ONRR Response: We thank this commenter for the insightful comment. 
We acknowledge that the proposed rule was not clear in providing a 
method for a lessee to use to value its gas used or lost along a 
pipeline prior to sale and disallowed fuel used in a gas plant. To add 
clarity and simplicity, we renumbered the proposed paragraph (d) to 
paragraph (e). For the new paragraph (d), we inserted new language that 
allow the lessee to value this gas for royalty purposes using the same 
royalty valuation method for valuing the rest of the gas that the 
lessee sells.
    In addition to the four situations above, and in the preamble to 
the proposed rule, we note that the lessee should use new paragraph (e) 
when the lessee is required to pay royalty on vented, flared, or 
otherwise lost gas as the BLM or Bureau of Safety and Environmental 
Enforcement (BSEE) determined.
    Public Comment: A company stated that the proposed regulation does 
not provide a method to value its gas when the lessee did not sell its 
gas but, rather, used it on site to generate electricity. It also 
argued that eliminating the fourth benchmark (netback) in the previous 
rule could negatively affect lessees that use gas to generate 
electricity because an index price is not an accurate indicator of 
market value.
    ONRR Response: We disagree with the comment because this final rule 
addresses the situation wherein a lessee does not sell its gas because 
the gas is used on site to generate electricity under Sec.  
1206.141(e). This paragraph provides that, where there is no sale of 
the gas and there is not an active index pricing point, we will value 
your gas under Sec.  1206.144(f).
2. Calculating Royalty Value for Processed Gas Sold Under an Arm's-
Length or Non-Arm's-Length Contract (Sec.  1206.142)
    Percentage-of-Proceeds (POP) contracts: Paragraph (a)(2) applies to 
situations where a lessee sells its gas before processing and must base 
their royalty payment on any constituent products, resulting from 
processing, such as residue gas, NGLs, sulfur, or carbon dioxide. This 
final rule requires lessees to value POP contracts, percentage-of-index 
contracts, and contracts with any variations of payment based on 
volumes or the value of those products as processed gas.
    Public Comment: Commenters from industry, industry trade groups, 
and STRAC opposed this change. Industry commenters and STRAC focused 
their comments on the reporting burden and financial impact of this 
change. One commenter explained, ``Because POP contracts have, since, 
November of 1991 been subject to the unprocessed gas valuation 
regulations, many companies do not have accounting systems set up to 
report anything other than a single product code 04 line.'' The 
commenters explain that this proposed change would impose significant 
accounting system costs and delays in reporting.
    One company stated that the current regulations recognize that the 
lessee no longer has title to or control over production after its POP 
buyer takes possession at the wellhead or plant inlet, highlighting 
that the lessee is not obligated to place residue gas and plant 
products in marketable condition. It believes that, by treating arm's-
length POP contracts as sales of processed gas, ONRR improperly places 
the burden on the lessees to bear the costs to place residue gas and 
plant products in marketable condition despite the fact that the 
lessees do not have title to or control over same.
    ONRR Response: We understand that this change may increase the 
number of reported lines and may require some companies to adjust their 
systems. Yet, if a company is in compliance under the previous rules 
(not taking more than the allowance limits without approval, adding 
back costs associated with placing the gas into marketable condition, 
adding back marketing fees, etc.), this change should not be overly 
burdensome. This change increases data transparency, more accurately 
values the products sold under these types of sales contracts, and 
allows us to better monitor allowances and account for royalty interest 
more quickly and accurately.
    Contrary to the commenter's assertions, past regulations did place 
the responsibility on lessees who sell their gas at the wellhead under 
POP-type contracts to place the residue gas and gas plant products into 
marketable condition at no cost to the Federal government. Simply 
selling the gas at the wellhead does not mean that the gas is in 
marketable condition--one must look to the requirements of the main 
sales pipeline. The U.S. District Court for the Northern District of 
Oklahoma supported ONRR's position under the past regulations, finding 
that, ``Whether gas is marketable depends on the requirements of the 
dominant end-users, and not those of intermediate processors'' 
Burlington Res. Oil & Gas Co. LP v. U.S. Dep't of the Interior, No. 13-
CV-0678-CVE-TLW, 2014 WL 3721210, at *11 (N.D. Okla. July 24, 2014).
    Valuation of keepwhole contracts: Paragraph (a)(3) states that the 
lessee must value gas processed under a ``keepwhole'' contract as 
processed gas. Under Sec.  1206.20, we define the term ``keepwhole 
contract'' as a processing agreement under which the processor 
compensates the lessee by delivering to the lessee a quantity of 
residue gas (after processing) that is equivalent to the quantity of 
gas the processor received (prior to processing), normally based on 
heat content, less gas used as plant fuel and gas that is unaccounted 
for and/or lost. The lessee does not receive NGLs under these 
contracts. We often find that lessees are confused about how to value, 
for royalty purposes, gas processed under such contracts and then sold. 
This provision clarifies that a lessee must value gas processed under a 
keepwhole contract as processed gas. That is, royalty is based on 100 
percent of the value of residue gas, 100 percent

[[Page 43349]]

of the value of gas plant products, plus the value of any condensate 
recovered downstream of the point of royalty settlement prior to 
processing, less applicable transportation and processing allowances.
    Public Comment: Commenters from industry trade groups and STRAC 
opposed this provision. They believe that ONRR should eliminate the 
requirement to report gas processed under a keepwhole contract as 
processed gas. The industry trade groups explained that companies do 
not have the data to report keepwhole contracts as processed gas. STRAC 
added that valuing keepwhole contracts as processed gas does not, in 
their experience, result in additional revenue collections, but it 
requires a significant amount of work for both auditors and industry.
    ONRR Response: Our regulations require lessees to base their 
royalties for gas sold after processing on the values of condensate, 
residue gas, and gas plant products resulting from processing gas 
produced from a Federal lease. Lessees sell gas processed under 
keepwhole contracts after processing, and, therefore, lessees should 
value their gas as such. This requirement also protects the public from 
hidden processing deductions that the lessee takes that may exceed the 
66\2/3\ percent limit of the value of the NGLs. Additionally, numerous 
entities rely on and scrutinize our data, making accurate reporting 
essential.
    To aid lessees in their effort to properly compute royalties for 
gas processed under a keepwhole contract, we published a reporter 
letter dated November 21, 2012 (Reporter Letter). The Reporter Letter 
provided guidance on how to report keepwhole contracts, including 
instructions for situations where the lessee receives no NGL volume or 
value data. It is important to note that, in most cases, this 
requirement does not increase the royalties that a lessee pays because 
the lessee may include the difference in value between the gallons of 
NGLs that the plant recovered and the MMBtu-equivalent of the NGLs 
returned to the producer in its processing allowance.
    First arm's-length sale: In this final rule, ONRR eliminated the 
non-arm's-length valuation benchmarks. Instead, this final rule 
requires lessees to value residue gas and gas plant products based on 
how they sell their residue gas and gas plant products (such as using 
(1) the first arm's-length-sale prices, (2) optional index prices, or 
(3) volume weighted average of the values established under this 
paragraph for each contract for the sale of gas produced from that 
lease). Under Sec.  1206.142(c)(2), if you sell or transfer your 
Federal residue gas and gas plant products to your affiliate, or some 
other person at less than arm's-length, and that person or its 
affiliate then sells the residue gas and gas plant products at arm's-
length, royalty value will be the other person's (or its affiliate's) 
gross proceeds under the first arm's-length contract. However, two 
exceptions apply: (1) Lessees may elect to use the index-pricing option 
under Sec.  1206.142(d) of this section, or (2) ONRR decides to value 
your residue gas and gas plant products under the default valuation 
provision in Sec.  1206.144.
    Public Comment: ONRR received comments from a State and a public 
interest group supporting ONRR's proposal for lessees to value non-
arm's-length dispositions of residue gas and gas plant products based 
on the first arm's-length sale rather than the benchmarks contained in 
the previous rule. Several industry commenters asserted that tracing 
their affiliates' arm's-length gross proceeds is complicated and 
burdensome. One industry trade group remarked that Sec.  1206.142(c) 
does not address costs unique to marketing and transporting CNG and 
LNG, where the first arm's-length sale may be at a distant, 
international market.
    ONRR Response: The values established in arm's-length transactions 
are the best indication of market value. We recognize that changes in 
industry and the marketplace may make it difficult for a lessee to 
value its gas using the benchmarks. To address these difficulties, we 
eliminated the benchmarks to provide early certainty and gave lessees 
with non-arm's-length sales the option to value gas based on the first 
arm's-length sale or index prices.
    Index-based valuation option: Paragraph (d)(1) applies to residue 
gas. It has the same index-price option as Sec.  1206.141(c)(i) through 
(vi). We discuss using index pricing points in Sec.  1206.141 of this 
Preamble.
    Paragraph (d)(2) contains the index-based pricing option for NGLs. 
Under paragraph (d)(2)(i), if you sell NGLs in an area with one or more 
ONRR-approved commercial price bulletins available at www.onrr.gov, you 
may choose one bulletin, and your value for royalty purposes would be 
based on the monthly average price for that bulletin for the production 
month. We consider you to be selling NGLs in an area with an ONRR-
approved commercial price bulletin if actual sales of NGLs that the 
plant processing your gas recovers are made using NGL prices in an 
ONRR-approved commercial price bulletin. For example, in our 
experience, actual sales of NGLs recovered in plants in New Mexico 
commonly reference Mont Belvieu, Texas, prices in Platts, while actual 
sales of NGLs recovered in plants in certain parts of Wyoming reference 
Mont Belvieu, Texas, or Conway, Kansas, prices. If you process your gas 
at one of these plants with these types of actual sales arrangements, 
we will consider you to be selling NGLs in an area with an ONRR-
approved commercial price bulletin. In that case, you may elect to 
value your NGLs using the index-price method if your NGLs meet the 
requirements for using that method. We will monitor actual sales of 
NGLs and eliminate any area where an active market using NGLs prices in 
an ONRR-approved commercial price bulletin ceases to exist.
    Under paragraph (d)(2)(ii), you may reduce the index-based value 
that you calculate under paragraph (d)(2)(i) by a specified amount to 
account for a theoretical processing allowance and Transportation and 
Fractionation (T&F). Therefore, the reduction includes two components 
that we calculated: (1) An allowance based on processing allowance 
information lessees report to us and (2) T&F based on our review of gas 
plant contracts and gas plant statements.
    For the processing allowance component, ONRR examined processing 
allowances that lessees and others reported from January 2007 through 
October 2011. We segregated the data into two subsets: (1) The Gulf of 
Mexico (GOM) and (2) onshore Federal leases and OCS leases other than 
those in the GOM. We segregated the leases geographically because the 
GOM is closer to major market centers at Mont Belvieu, Napoleonville, 
and Geismer/Sorrento and, generally, has its own processing, 
transportation, and fractionation regimen that is distinct from the 
rest of the country. It is not fair or accurate to benchmark processing 
for the entire country based on the economics of GOM processing.
    We could not segregate non-arm's-length processing allowances 
because lessees do not identify processing allowances as arm's-length 
or non-arm's-length when they report to ONRR. Rather, we calculated a 
weighted-average cents-per-gallon processing allowance by month for 
both GOM and all other Federal leases. Using the weighted average 
cents-per-gallon processing allowance that we calculated, we determined 
the average allowance rate over the five-year period, along with the 
maximum and minimum monthly rates as follows:

[[Page 43350]]



------------------------------------------------------------------------
                                                       GOM       Other
                                                     ([cent]/   ([cent]/
                                                       gal)       gal)
------------------------------------------------------------------------
Average Rate......................................         17         22
Maximum Rate......................................         29         32
Minimum Rate......................................         10         15
------------------------------------------------------------------------

    Because we intend for this option to provide a simple method for us 
to calculate and provide to lessees, we used the minimum, rather than 
the average rate, for the processing allowance portion of the 
deduction. For both the GOM and all other Federal leases, the minimum 
rate is seven cents less than the average rate. We find that (1) the 
minimum allowance best protects the public interest and (2) a lessee 
experiencing higher allowable costs than this rate does not have to 
elect to use this option and the lower cost allowance. Moreover, seven 
cents is a reasonable tradeoff given the simplicity, certainty, and 
commensurate administrative savings that this option would provide to a 
lessee.
    For the T&F part of the reduction, we examined contracts that 
specified T&F. If contracts did not specify T&F, we looked at the gas 
plant statements. If the statements listed T&F as a line item, we used 
that line item as the T&F. If the statements did not list T&F as a line 
item, we calculated the difference between the price on the plant 
statement and an appropriate published price to approximate the T&F. We 
then averaged these T&F costs for GOM, New Mexico, and other, as 
follows:

----------------------------------------------------------------------------------------------------------------
                                                 GOM                   New Mexico                 Other
----------------------------------------------------------------------------------------------------------------
Average T&F..........................  5[cent]/gal............  7[cent]/gal............  12[cent]/gal.
----------------------------------------------------------------------------------------------------------------

    We broke out New Mexico because the T&F fees for New Mexico plants 
were consistently around seven cents per gallon and were considerably 
less than for other onshore plants. We then added the processing 
allowances that we calculated and the T&F. Based on the five years of 
data discussed above, we calculated that the total NGLs reductions that 
lessees could use under this option are as follows:

----------------------------------------------------------------------------------------------------------------
                                                 GOM                   New Mexico                 Other
----------------------------------------------------------------------------------------------------------------
NGLs Deduction.......................  15[cent]/gal...........  22[cent]/gal...........  27[cent]/gal.
----------------------------------------------------------------------------------------------------------------

    Under paragraph (d)(2)(ii), rather than publish the reductions in 
the CFR, we will post the reductions at www.onrr.gov for the geographic 
location of your lease. ONRR will calculate the reductions using the 
method explained above. This process will give us the flexibility to 
quickly recalculate and provide revised reductions to lessees in 
response to market changes. This method is binding on you and us. Under 
paragraph (d)(4), we will update the allowable reductions periodically 
using this method and post changes at www.onrr.gov.
    Paragraph (d)(2)(iii) explains that, after you select an ONRR-
approved commercial price bulletin available at www.onrr.gov, you may 
not select a different commercial price bulletin more often than once 
every two years. Under paragraph (d)(3), you may not take any other 
deductions from the value that you used under this paragraph (d) 
because it already includes reductions for transportation and 
processing.
    Paragraph (e) mirrors Sec.  1206.141(d); this explains how you must 
value certain volumes of processed gas or NGLs that are used as fuel, 
lost, or retained as a fee under the terms of a sales or service 
agreement.
    Paragraph (f) mirrors Sec.  1206.141(e); this explains how you must 
value your processed gas and NGLs if you have no written contract for 
the sale of gas or no sale of the gas subject to this section.
    Public Comment: Several industry commenters noted that ONRR 
provided no adjustment to the index price for transportation of the NGL 
component of the gas stream from the wellhead to the gas plant. The 
only adjustment is for the costs of transporting and fractionating the 
recovered NGLs. One commenter suggested that ONRR use the same 
adjustment that ONRR used in calculating the index-based value for the 
unprocessed or residue gas (10 percent, but not less than 10 cents per 
MMBtu or more than 30 cents per MMBtu).
    ONRR Response: We do not agree that an adjustment is necessary. The 
adjustment would be small, and not including it is fair considering our 
use of the average index price instead of the high index price. This 
final rule does not require a lessee to use the index option, but the 
lessee can elect to base its royalty value on the first arm's-length 
sale.
    Public Comment: One industry trade group requested that ONRR 
clarify whether we intend to use the ``average highest price'' or the 
``average average price'' for the index-based valuation method for 
NGLs.
    ONRR Response: In our experience, NGL price publishers publish an 
average and high NGL price. They do not publish an ``average average'' 
or ``average high'' price. We will use the average index price.
    Public Comment: One industry trade group commented that New Mexico 
producers were particularly disadvantaged by the T&F rates that ONRR 
proposed.
    ONRR Response: Our experience indicates that seven cents per gallon 
is a reasonable estimate for T&F rates in New Mexico. T&F rates are 
generally lower in New Mexico than in the rest of the country because 
New Mexico producers have more direct access to Mont Belvieu, Texas.
    Public Comment: An industry commenter questioned what remedy a 
lessee would have if ONRR did not follow the method set forth in the 
preamble. The commenter noted that the proposed regulation provided 
that an election to use index-based pricing cannot be changed more 
often than once every two years. Then the commenter suggested that it 
is hard for a company to make an election when the basis for making the 
election, including ONRR's posting of the amounts that can be deducted, 
can be changed during the two-year period for which the election was 
made.
    ONRR Response: The two-year election period offers sufficient 
protection for lessees if we change the rates. Any changes to rates 
will be based on changes to the markets, which should generally 
correspond to changes that producers would see if they were reporting 
gross proceeds.
    No-sale situations: Paragraph (e)(1) provides that, if you have no 
written contract or no sale of gas subject to this section and there is 
an index pricing point for the gas, then you must value your gas under 
the index-pricing provisions of paragraph (d) of this section unless 
ONRR values your gas under Sec.  1206.144. We intended this

[[Page 43351]]

provision to address situations including, but not limited to, when (1) 
the lessee sells its gas to an affiliate, and the affiliate uses the 
gas in its facility; (2) the lessee sells its gas to an affiliate, the 
affiliate resells the gas to another affiliate of either the lessee or 
itself, and that affiliate uses the gas in its facility; (3) the lessee 
uses the gas as fuel for its other leases in the field or area; or (4) 
the lessee delivers gas to another person as payment for an overriding 
royalty interest that the other person holds.
    Public Comment: A commenter noted that lessees do not sell gas or 
gas plant products used or lost along the pipeline and may currently 
value those volumes under the benchmark valuation regulations The 
commenter stated that, previously, using the price that the lessee 
received for the gas that it sold as the basis to value its gas used or 
lost along the pipeline was a much more certain method of valuing gas, 
which also satisfied benchmark two. Instead, the commenter argues that 
the rule requires the lessee to submit a proposed valuation method and 
be subject to having to make retroactive changes if ONRR does not 
accept the proposed method. The commenter argued that it was unfair to 
require lessees who cannot otherwise use the index-based option (those 
making arm's-length sales) to have to use the index-based pricing to 
value gas or gas plant products used or lost along a pipeline and adds 
unnecessary complexity.
    ONRR Response: We thank this commenter for the insightful comment. 
We acknowledge that the proposed rule was not clear in providing a 
method for which a lessee shall value gas used or lost along a pipeline 
prior to sale and disallowed fuel used in a gas plant. In an effort to 
add clarity and simplicity, we will, therefore, renumber the proposed 
paragraph (e) to paragraph (f). For the new paragraph (e), we inserted 
new language that allows the lessee to value this gas for royalty 
purposes using the same royalty valuation method for valuing the rest 
of the gas that the lessee sells.
3. Determination of Correct Royalty Payments (Sec.  1206.143)
    Default: ONRR added a default valuation provision that allows us to 
value your gas, residue gas, or gas plant products under Sec.  1206.144 
or any other provision in this subpart D. We addressed comments 
pertaining to the ``default provision'' paragraph, which we detail in 
Sec.  1206.101, of this Preamble.
    Public Comment: All of the commenters who addressed the default 
provision under Federal oil had the same comments for Federal gas, and 
we will not repeat them here. Please refer to the public comments for 
Federal oil for an overall discussion of the default provision.
    Specifically for gas, several commenters stated that ONRR lists 
comparability factors in its valuation method that contradict what ONRR 
permits lessees to consider. They state, for example, that ONRR may 
look to the value of like-quality gas, residue gas, or gas plant 
products in the same or nearby fields or plants, but it is not 
permitting lessees the option to use these standards as part of their 
valuation processes in the first instance.
    ONRR Response: We will only respond, here, to those comments that 
are specific to gas, residue gas, and gas plant products. For a broader 
response to the default provision, because it also relates to Federal 
gas, please see ONRR's response to Federal oil, which we detail in 
Sec.  1206.101, of this Preamble.
    We disagree with commenters that state that we list comparability 
factors in our default valuation method that contradict what we permit 
the lessees to consider. Valuation, first and foremost, is generally 
based on the gross proceeds accruing to the lessee under an arm's-
length contract or received under the first arm's-length sale following 
a sale to an affiliate. Only in rare situations, when normal valuation 
methods are not viable or there has been other extenuating 
circumstances, will we defer to the valuation criteria listed in Sec.  
1206.144.
    This final rule delineates factors that we may consider if we 
decide to determine the value of natural gas for royalty purposes under 
the default provision. Those factors may include, but are not limited 
to the following: the value of like-quality gas in the same field or 
nearby fields or areas; the value of like-quality residue gas or gas 
plant products from the same plant or area; public sources of price or 
market information that we deem to be reliable; information available 
or reported to us, including but not limited to, on Form ONRR-2014 and 
Form ONRR-4054; costs of transportation or processing, if we determine 
that they are applicable; and any information that we deem relevant 
regarding the particular lease operation or the salability of the gas.
    Misconduct: ONRR added a new definition for the term misconduct. We 
addressed comments pertaining to this definition, which we detail in 
Sec.  1206.20, of this Preamble.
4. Determination of gas value for royalty purposes (Sec.  1206.144)
    Default: ONRR added a default valuation provision which allows us 
to value your gas under Sec.  1206.144 or any other provision in this 
subpart. We addressed comments pertaining to the ``default provision'' 
paragraph, which we detail in Sec.  1206.101, in this Preamble.
    Area: ONRR removed the phrase ``legal characteristics'' from the 
definition of area. We addressed comments pertaining to this definition 
and the regulations that it affects, detailed in Sec.  1206.105, in 
this Preamble.
5. Responsibility To Market Production and To Place Production into 
Marketable Condition (Sec.  1206.146)
    Public Comment: Although ONRR did not modify the wording in this 
section, several commenters argue that our proposal eliminates 
separately defined requirements for processed and unprocessed gas and 
replaces them with a consolidated marketable condition requirement. 
This, commenters argue, may result in the lessee being required to 
place processed gas in marketable condition twice--once as gas and 
again as residue gas.
    ONRR Response: The regulations have always required the lessee to 
put its production into marketable condition at no cost to the Federal 
government. This requirement remains unchanged, as does a lessee's duty 
to put its production into marketable condition.
6. Valuation determination requests (Sec.  1206.148)
    Guidance and Determinations: ONRR clarified how a lessee may 
request a valuation determination from us. We addressed comments 
pertaining to guidance and determinations in Sec.  1206.108. For the 
reasons discussed in response to comments, we deleted the words ``or 
guidance'' from the title and paragraph (a) of this section.
7. Accounting for Comparison (Sec.  1206.151)
    ONRR proposed to move the current provisions under Sec.  1206.155 
to proposed Sec.  1206.151 and requested comments regarding whether or 
not to retain the requirement to perform accounting for comparison 
(dual accounting) for gas produced from Federal leases.
    Public Comment: Industry and State commenters supported removing 
the Federal dual accounting provision from the regulations. Commenters 
stated that, because residue gas is now valued based on the first 
arm's-length sale or index-based option, the criteria that triggered

[[Page 43352]]

dual accounting, a non-arm's-length sale of residue gas after 
processing, is no longer valid.
    STRAC agreed that, under current market conditions, accounting for 
comparison was no longer necessary, but they questioned how ONRR would 
respond to potential changes in the gas market in the future.
    ONRR Response: We removed the requirement to perform accounting for 
comparison for gas produced from Federal leases from the final rule. We 
agree that the gas valuation method under Sec.  1206.142 renders 
accounting for comparison for Federal gas production unnecessary. 
Should significant changes in the gas market occur in the future, we 
will revisit the need for Federal dual accounting in a future 
rulemaking. Further, Sec.  1206.140(c) recognizes the primacy of lease 
terms over regulations and, should the terms of a lease require dual 
accounting, lessees are clearly subject to the dual accounting 
requirement.
8. General Transportation Allowance Requirements (Sec.  1206.152)
    Subsea gathering: ONRR added a new provision stating that you may 
not take a transportation allowance for the movement of gas produced on 
the OCS from the wellhead to the first platform. This addition, along 
with the changes to the definition of gathering, rescinds the Deep 
Water Policy. We addressed comments pertaining to this issue, which we 
detail in Sec.  1206.110, in this Preamble.
    Fifty-percent allowance cap and retroactive change: ONRR eliminated 
the regulation allowing us to approve transportation allowances in 
excess of 50 percent of the value of a lessee's gas production. Any 
prior approvals will terminate on the date when the rule becomes final. 
We addressed comments pertaining to these issues, which we detail in 
Sec.  1206.110, in this Preamble.
    Eliminating transportation factors: Previously, ONRR allowed 
lessees to net transportation from their gross proceeds when the 
lessees' arm's-length contract reduced the price of the gas by a 
transportation factor. We eliminated this provision and, instead, 
require lessees to report such costs as a separate entry on Form ONRR-
2014. We addressed comments pertaining to this issue, which we detail 
in Sec.  1206.110, in this Preamble.
    Misconduct: ONRR added a new definition for the term 
``misconduct.'' We addressed comments pertaining to this issue, which 
we detail in Sec.  1206.20, in this Preamble.
    Default: We addressed comments pertaining to the ``default 
provision'' paragraph, which we detail in Sec.  1206.101, in this 
Preamble.
    Unreasonably high transportation costs: We addressed comments 
pertaining to this issue, which we detail in Sec.  1206.104, in this 
Preamble.
9. Determination of Transportation Allowances for Arm's-Length 
Transportation Allowances (Sec.  1206.153)
    Pipeline losses: We addressed comments pertaining to this issue, 
which we detail in Sec.  1206.111, in this Preamble.
    In the proposed rule, we removed the provision in the previous 
regulations under Sec.  1206.157(b)(5). We neglected to remove 
regulatory language in proposed Sec.  1206.153(b)(7). Therefore, in 
this final rule, we deleted, ``or ONRR approves your use of a FERC or 
State regulatory-approved tariff as an exception from the requirement 
to calculate actual costs under Sec.  1206.154(l) of this subpart.''
    Written contracts: We added a new provision stating that we will 
determine transportation allowances if lessees do not have a written 
contract for the arm's-length transportation of gas. We addressed 
comments pertaining to this issue, which we detail in Sec.  1206.104, 
in this Preamble.
    Eliminating transportation factors: Previously, we allowed lessees 
to net transportation from their gross proceeds when the lessees' 
arm's-length contract reduced the price of the gas by a transportation 
factor. We eliminated this provision and alternatively require lessees 
to report such costs as a separate entry on Form ONRR-2014. We 
addressed comments pertaining to this issue, which we detail in Sec.  
1206.110, in this Preamble.
    Boosting: Under paragraph (c)(8), we specify that the costs of 
boosting residue gas are not allowable costs of transportation.
    Public Comment: An industry commenter argued that this new 
provision effectively requires the unbundling of arm's-length 
transportation agreements. Industry also argues that the additional 
disallowance of boosting residue gas in this section and in Sec.  
1202.151(b) is either redundant or results in the lessee having to pay 
for some marketable condition costs twice for processed gas. Industry 
states that boosting residue gas is part of plant costs, and it is not 
associated with a transportation system or transportation allowance.
    An industry commenter suggested that eliminating the proposed 
boosting language in paragraph (c)(8) will ensure consistency in 
product valuation for all natural gas, whether processed, unprocessed, 
conventional, or coal bed methane and all plants (cryogenic, lean oil 
absorption, refrigeration, and CO2 removal). According to 
the commenter, elimination of the boosting language will also ensure 
proper treatment involving leases that produce at a pressure above the 
marketable condition requirement or for offshore leases where the gas 
leaves the production platform at or above the marketable condition 
pressure by requiring the gas be placed into marketable condition only 
once.
    ONRR Response: Current regulations and case law make clear that the 
cost incurred--including any fuel used--to boost gas (such as compress 
residue gas after processing) is not a deductible cost of processing or 
transportation (30 CFR 1202.151(b); see also Devon Energy Corporation 
v. Kempthorne, 551 F.3d 1030 (D.C. Cir. 2008), cert. denied, 130 S. Ct. 
86 (2009), (finding that boosting is not deductible even if gas is in 
marketable condition before entering a gas processing plant)). Yet a 
number of members of industry continue to deduct costs incurred to 
boost residue gas as either a processing or a transportation allowance, 
and they argue that it is proper to do so. The inclusion of paragraph 
(c)(8) reinforces current regulations and case law and therefore we 
retained it in the final rule.
10. Determination of Transportation Allowances for Non-Arm's-Length 
Transportation Contracts (Sec.  1206.154)
    Pipeline losses: Under paragraph (c)(2)(ii), we eliminated the 
provision that allows lessees to deduct the costs of pipeline losses, 
both actual and theoretical, under non-arm's-length transportation 
situations. We addressed comments pertaining to this issue, which we 
detail in Sec.  1206.111, in this Preamble.
    BBB bond rate: We reduced the multiplier on any remaining 
undepreciated capital costs from 1.3 to 1.0 times the Standard & Poor's 
BBB bond rate. We addressed comments pertaining to this issue, which we 
detail in Sec.  1206.112, in this Preamble.
    FERC or state-regulatory-agency approved tariffs: We removed the 
provisions allowing a lessee with a non-arm's-length contract to apply 
for an exception to use FERC or State-regulatory-agency approved 
tariffs as an exception from the requirements to calculate actual 
costs.
    Public Comment: Several companies and industry trade groups opposed 
removing the provision, stating that it lacked justification. One 
commenter stated, ``Many of these situations involve affiliated 
pipelines where obtaining the information to do these calculations 
would be problematic and

[[Page 43353]]

burdensome due to the governmental restrictions placed on pipeline 
companies in sharing information with shippers.''
    ONRR Response: Lessees may deduct their reasonable actual costs of 
transportation under this section. The burden lies with the lessee to 
calculate these reasonable actual costs of transportation. We removed 
this rarely-used provision to apply for an exception to create 
consistency with the Federal oil valuation regulations and promote a 
more consistent application of the actual cost allowance method.
11. Reporting Requirements for Arm's-Length Transportation Contracts 
(Sec.  1206.155)
    Eliminating transportation factors: Eliminating transportation 
factors will require lessees to report any transportation costs 
embedded in an arm's-length contract as a separate line entry on Form 
ONRR-2014. We addressed comments pertaining to this issue, which we 
detail in Sec.  1206.115, in this Preamble.
12. Reporting Requirements for Arm's-Length Transportation Contracts 
(Sec.  1206.156)
    In the proposed rule, we removed the provision in the previous 
regulations under Sec.  1206.157(b)(5). We neglected to remove 
regulatory language in proposed Sec.  1206.156(d). Therefore, in this 
final rule, we deleted this paragraph.
13. Processing Allowances (Sec.  1206.159)
    We eliminated the regulation allowing us to approve processing 
allowances in excess of 66\2/3\ percent of the value of a lessee's gas 
production. Any prior approvals will terminate on the date when the 
rule becomes final. We addressed issues related to prior approval 
terminations, which we detail in Sec.  1206.110, in this Preamble.
    Public Comment: We received comments from States and public 
interest groups generally supporting eliminating ONRR approval to 
exceed the 66\2/3\-percent allowance cap on processing allowances. 
However, a State commenter asserted that the 66\2/3\-percent cap, 
itself, was too broad. A State suggested that ONRR calculate allowance 
caps for each State and use a percentage based on the average 
processing costs in each State over a ten-year period. A State 
commenter suggested that ONRR update and post such percentages on its 
Web page.
    ONRR received comments from companies and industry trade groups 
opposing the proposed rule's elimination of ONRR approval to exceed a 
66\2/3\-percent limitation on processing allowances. These commenters 
generally stated that the right to request approval to exceed the 66\2/
3\-percent limitation needs to be reinstated because its removal denies 
a lessee the ability to deduct all of its actual, reasonable, and 
necessary processing costs when those costs exceed 66\2/3\ percent. The 
commenters believe that this is especially true when the physical make-
up of the gas warrants complex plant designs that result in higher 
costs. Last, commenters take issue with ONRR terminating any approval 
that it previously issued for a lessee to exceed the 66\2/3\-percent 
limitation.
    ONRR Response: The comments regarding the 66\2/3\-percent 
processing allowance mirror the comments that we received for the 50-
percent limitation on transportation allowances for oil. Please refer 
to our comments regarding the ``Fifty-percent allowance cap,'' which we 
detail in Sec.  1206.110, in this Preamble.
    Extraordinary processing allowances and retroactive changes: We 
eliminated the provision that allows a lessee to request an 
extraordinary processing cost allowance. We previously allowed lessees 
to deduct processing costs up to 99 percent of the value of the gas 
plant products extracted and up to 50 percent of the value of the 
residue gas. This final rule also terminates the two existing 
extraordinary processing cost allowance approvals. We addressed issues 
related to the prior approval terminations, which we detail in Sec.  
1206.110, in this Preamble.
    Public Comment: Industry commenters and a State commented that ONRR 
should retain the extraordinary processing cost allowance provision and 
argued that ONRR failed to provide specific evidence that circumstances 
or improvements in technology have changed enough to warrant the 
termination of the two existing approvals.
    ONRR Response: The Department added the extraordinary processing 
cost allowance provision to the 1988 regulations to account for the 
costs of processing unique gas streams based on the technology 
available at that time. The Department has not approved an 
extraordinary processing cost allowance since 1996, and we maintain 
that the markets and the technology have changed sufficiently such that 
this provision and these approvals are no longer necessary.
    Default: In drafting this final rule, we did not include the 
default provision in this section. We intended to include the default 
provision here as evidenced by our discussion of the default provision 
in the economic analysis of the proposed rule. Therefore, we added the 
default provision in Sec.  1206.159(e), which applies to processing 
allowances calculated under Sec. Sec.  1206.160 and 1206.161. We 
addressed comments pertaining to the ``Default Provision'' paragraph, 
which we detail in Sec.  1206.101, in this Preamble.
14. Processing Allowances Under an Arm's-Length Contract (Sec.  
1206.160)
    Unreasonably high processing costs: We moved the requirements for 
non-arm's-length processing allowances to a separate Sec.  1206.161. 
Because the requirements for determining processing allowances under an 
arm's-length contract are essentially the same as those for determining 
transportation allowances under an arm's-length contract, we made the 
same changes to processing allowances in this section as those that we 
made for arm's-length transportation allowances. Newly added paragraph 
(c) applies if you have no written contract for arm's-length processing 
of gas. In that case, we will determine your processing allowance under 
Sec.  1206.144. We addressed comments pertaining to this general issue, 
which we detailed under Sec.  1206.104, in this Preamble.
    Misconduct: We added a new definition for the term misconduct. We 
addressed comments pertaining to this issue, which we detailed under 
Sec.  1206.20, in this Preamble.
    Default: We addressed comments pertaining to the ``default 
provision,'' which we detail under Sec.  1206.101, in this Preamble. In 
conjunction with our additions in Sec.  1206.159(e) explained above, 
and to make this section consistent with the transportation allowances 
sections, we deleted paragraph (a)(3).

D. Specific Comments on 30 CFR Part 1206--Product Valuation, Subpart 
F--Federal Coal

1. Calculating Royalty Value for Coal I or My Affiliate Sell(s) Under 
an Arm's-Length or Non-Arm's-Length Contract (Sec.  1206.252)
    Index prices for coal lessees that do not sell under arm's-length 
contracts: In contrast to the Federal oil and gas valuation 
regulations, the coal regulations do not allow lessees that do not sell 
their coal under arm's-length contracts to value their coal based on 
index prices.
    Public Comment: ONRR received comments from industry trade groups, 
public interest groups, individual commenters, and companies suggesting 
that ONRR provide coal lessees who do not sell coal under arm's-length

[[Page 43354]]

contracts the option of valuing coal based on index prices, similar to 
the options for oil and gas lessees. The commenters believe that using 
an index price would provide simplicity, predictability, and 
transparency to the value of coal not sold under arm's-length 
contracts. ONRR received a comment from a Tribe indicating that it 
would be willing to accept index prices as a floor value of coal if 
there is a reliable index. Several commenters proposed that ONRR could 
generate an index to value coal not sold at arm's-length.
    ONRR Response: We appreciates the comments, but declined to provide 
lessees who do not sell their coal under arm's-length contracts the 
option to use index prices to value their coal. As mentioned in the 
``General Comments'' section, we are not aware of any published index 
prices for coal that cover a wide array of coal production. Currently, 
there are few, if any, indexes for coal, and they are not as widely 
used as they are for oil and gas. Also, although the existing indexes 
vary depending on MMBtu content, they do not take into account other 
variations in the quality of coal, such as ash or sulfur content.
    As to the comments that we should generate an index price for 
lessees to use, we decline to do so at this time. First, as mentioned 
above, there are no reliable indexes for coal like there are for oil 
and gas, making it difficult for us to create index-based prices 
similar to those used in our Indian oil and gas regulations. Second, if 
we use arm's-length sales from the royalty reports that we receive, we 
risk divulging proprietary data. We will monitor the coal market and 
may be open to considering an index-based valuation option if the 
indexes become viable in the future.
    First arm's-length sales: Consistent with how we require lessees to 
value other commodities, we are requiring lessees to value non-arm's-
length dispositions of Federal coal at the first arm's-length sale.
    Public Comment: ONRR received numerous comments on our proposal to 
remove the benchmarks and, instead, value coal at the first arm's-
length sale. Many industry commenters petitioned ONRR to retain the 
previous rule's benchmark system to value coal sold under non-arm's-
length contracts. Some commenters felt that valuing coal at the first 
arm's-length sale was unnecessarily complex. The commenters stated that 
using the first arm's-length sale as value may require the lessee to 
use international or electricity sales as the basis of value, which 
does not reflect the value of coal sold at the lease. Instead, some 
commenters generally expressed a view that the previous rule's 
benchmark system, or some modification thereof, would be a better 
option to determine value. Some commenters felt that the first 
benchmark, which requires lessees to compare their non-arm's-length 
sales with arm's-length sales in the same field or area, is the 
appropriate measure of value for coal not sold at arm's-length. In 
contrast, other commenters felt that the proposed rule did not go far 
enough. Instead, these commenters recommended that ONRR value the coal 
based on its final--not its first--arm's-length sale.
    ONRR Response: The values established in arm's-length transactions 
are the best indication of market value. There is ample evidence that 
arm's-length sales provide a consistent and accurate measure of all 
commodities for which we collect royalties. We found that the 
benchmarks were difficult to use in practice. There have been disputes 
over comparable sales, which benchmark to use, and how to properly 
apply those benchmarks. To address these difficulties, we simplified 
the rule by requiring lessees to value coal based on the first arm's-
length sale.
    Previously, when lessees sold coal under a non-arm's-length 
contract, the regulations required the lessee to use the first 
applicable ``benchmark'' to establish value. The first benchmark was 
the gross proceeds accruing to the lessee under its non-arm's-length 
sale, provided those gross proceeds were comparable to the gross 
proceeds that accrued to other producers not affiliated with the lessee 
under arm's-length sales of like-quality coal in the same area. To 
compare such sales, the lessee looked at prices, timing, markets, 
quality, and quantity of coal. The second benchmark was prices reported 
to a public utility commission. The third was prices reported to the 
Energy Information Administration (EIA) of the Department of Energy. 
The fourth benchmark required the lessee to use other relevant matters, 
including spot market prices, or other information concerning the 
particular lease operation or salability of the coal. The fifth 
benchmark was a netback method.
    Although many commenters advocated for the first benchmark, 
industry and ONRR found it difficult to implement this provision. 
Acquiring arm's-length contracts to compare with the lessee's gross 
proceeds was challenging and, at times, impossible for lessees. Lessees 
cannot use their or their affiliates' comparable sales. Only in rare 
circumstances did the lessee have access to its competitor's 
information regarding the price that the competitor receives for its 
coal. Further, we cannot obtain or verify contracts for comparable-
quality coal sold from fee or State lands. Industry and ONRR also found 
that it was difficult to ascertain definitively which arm's-length coal 
sales were comparable and which ones were not. Based on our experience, 
arm's-length sales are a superior indicator of value to the remaining 
benchmarks.
    Valuing coal sold by coal cooperatives: Section 1206.252(c) 
addresses sales by coal cooperatives to their members or between 
members. In keeping with our intent to value commodities, whenever 
possible, at their first arm's-length sale, we provided a definition of 
the term ``coal cooperatives'' in Sec.  1206.20 and addressed sales by 
coal cooperatives to their members or between members in this section. 
Principally, coal cooperatives are formed because of some degree of 
mutual economic or other business interest. Consequently, transactions 
within coal cooperatives lack the opposing economic interests 
characteristic of arm's-length sales. Because coal cooperatives engage 
in non-arm's-length sales to and between members, we require lessees to 
base the value of their coal at the first arm's-length sale, wherever 
that may finally occur. In some cases, this may be the sale of 
electricity generated in a coal-fired plant.
    Public Comment: ONRR received comments supporting our distinction 
of coal cooperatives as engaging in other than arm's-length sales. 
These commenters expressed concerns that coal producers, logistics 
companies, and even generators of coal-fired electricity would take 
advantage of their affiliated status and sell coal to each other at 
less than market prices, thereby lowering their royalty liabilities. 
Conversely, numerous commenters objected to our definition of coal 
cooperatives. These commenters argued that our definition and the 
application of our rules to coal cooperatives did not accurately 
reflect the corporate structure of cooperatives, would penalize small 
producers, and deviates from our intent to value coal at the mine.
    ONRR Response: We seek a clear, consistent, and repeatable standard 
for valuing coal at its true market value. Coal cooperatives of varying 
forms (and complexity) are, primarily, designed for mutual economic 
advantage. We share the concerns that some commenters expressed that 
sales within coal cooperatives may not reflect the true market value of 
the coal. We require

[[Page 43355]]

lessees to value coal consistent with other commodities--at their first 
arm's-length sale between entities with competing economic interests, 
rather than common interests. We disagree with the comment that the 
definition of coal cooperatives is ``unnecessary.'' In fact, given the 
unique institutional nature of cooperatives in the coal industry--
corporate relations among mine producers, logistics operations, 
electric generation, and overseas sales--that is not commonly found in 
markets for oil and gas, we deemed it imperative to define coal 
cooperatives for royalty purposes.
    Valuing coal based on sales of electricity: In some situations, the 
lessees do not sell coal but, rather, transfer the coal along a series 
of non-arm's-length transactions to an affiliated generator of coal-
fired electricity, who then sells electricity generated from the coal. 
We require lessees to base the value of the coal on the value of 
electricity sold, less applicable deductions for transmission, 
generation, coal washing, and transportation.
    Public Comment: We received numerous comments, both supporting and 
opposing, using the value of electricity to value coal in cases of no 
sales or sales within coal cooperatives. Supporters argued that, in 
cases of no sales or non-arm's-length sales across coal cooperatives, 
assessing the value of coal as that of the generated electricity gives 
the most accurate representation of the coal's value. Some of these 
commenters argued that coal should be valued at the last arm's-length 
sale of electricity. Opponents argued that valuing coal using electric 
sales was a violation of the MLA, ignored and oversimplified the 
complexities of electric markets and contracts, and was 
administratively burdensome. In addition, they argued that ONRR's 
reference to geothermal regulations for valuing electricity was outside 
the scope of coal valuation.
    ONRR Response: We disagree with comments asserting that using 
electric sales to value Federal coal, for royalty purposes, is 
inconsistent with the MLA. Rather, the MLA expressly provides the 
Secretary's discretion to determine value: ``A lease shall require 
payment of a royalty in such amount as the Secretary shall determine of 
not less than 12\1/2\ per centum of the value of coal as defined by 
regulation.'' 30 U.S.C. 207. This rule simply defines the value of 
coal.
    As previously stated, based on our experience, arm's-length sales 
are the best indicator of value. Due to the complexity of affiliated 
interests across coal mining, logistics, and sales that many commenters 
referenced, the first arm's-length sale could easily be the sale of 
generated electricity. According to the EIA, in 2014, over 93 percent 
of coal consumption was used in electric generation nationally.
    We require lessees to value coal based on the first arm's-length 
sale, regardless if that sale is for coal or electricity. However, the 
rule does allow lessees to deduct costs associated with converting the 
coal to electricity to arrive at the value of the coal at the lease--
not the value of the electricity. We will only use sales of electricity 
to value coal in situations where the first arm's-length sale is the 
sale of electric power along a series of no sales or non-arm's-length 
sales.
2. Determination of Correct Royalty Payments (Sec.  1206.253)
    Default: We added a default valuation provision in Sec.  1206.253 
under which we can value a lessee's Federal coal if we decide to do so 
using the criteria in Sec.  1206.254 or any other provision in these 
subparts.
    Public Comment: Almost unanimously, industry commenters and others 
who support industry's position objected to the use of ONRR's proposed 
default provision for coal. Several industry commenters argued against 
ONRR's ability to determine royalty value when coal is sold for 10 
percent less than the lowest reasonable measures of market value. 
Commenters stated that some companies can negotiate better prices than 
others based on size and bargaining power.
    Several industry trade associations stated that, under its default 
provision, ONRR could upend reasonable and settled expectations 
whenever we decide for any reason that it dislikes any given lessee's 
reported coal valuation. These industry commenters also believe (1) 
that this provision does not allow ONRR to honor arm's-length contracts 
and gross proceeds as the basis of valuation as in the past; (2) there 
is a lack of specific criteria for determining what is reasonable 
valuation; (3) the default provision should not be used for simple 
reporting errors; and (4) the default provision is burdensome, an 
overreach of valuation authority, and creates uncertainty.
    Several public interest groups suggested that the default provision 
should be mandatory and not discretionary. They supported ONRR's 
proposal to establish a default valuation mechanism, which provides the 
agency with needed authority to ascertain the value of Federal and 
Indian coal where the government otherwise would fail to garner a fair 
return on its resource as the result of a lessee's misconduct. The 
commenters believe that the sources of information upon which ONRR 
proposes to base its determination of the coal's value are appropriate 
and, to the extent that they include publicly accessible information, 
would promote transparency. The comments from public interest groups 
stated that, when industry fails to abide by the terms of its 
commitment to market Federal coal for the mutual benefit of the lessee 
and the Federal government, thereby depriving the government of 
royalties on the full market value of its coal, the regulations should 
eliminate the lessee's privilege to continue to determine its own coal 
value and royalty payments. A comment from a public interest group 
stated that hesitancy of invoking this default proposition guts the 
method's efficacy and limits the extent to which the rule will close 
the first arm's-length sale loophole.
    ONRR Response: We disagree with the commenters' statements that the 
default provision is a radical departure from our historical valuation 
policy. The regulatory changes do not alter the underlying principles 
of the current regulations. For example, nothing in this final rule 
changes the Department's requirement that, for the purposes of 
determining royalty, the value of coal produced from Federal leases is 
determined at or near the lease. And nothing in this final rule 
modifies or alters the fact that gross proceeds from arm's-length 
contracts are the best indication of market value.
    The default provision addresses valuation situations where 
circumstances result in the Secretary's inability to reasonably 
determine the correct value of production. Such circumstances include, 
but are not limited to, (1) the lessee's failure to provide documents; 
(2) the lessee's misconduct; (3) the lessee's breach of the duty to 
market; or (4) any other situation that significantly compromises the 
Secretary's ability to reasonably determine the correct value. The 
mineral statutes and lease terms give the Secretary the authority and 
considerable discretion to establish the reasonable value of production 
by using a variety of discretionary factors and any other information 
that the Secretary determines is relevant. The default provision simply 
codifies the Secretary's authority to determine the value of production 
for royalty purposes and specifically enumerates when, where, and how 
the Secretary will use that discretion.
    Under this new rule, we will not second-guess arm's-length 
contracts to any greater or lesser degree than we

[[Page 43356]]

have historically. We have never tacitly accepted values received under 
arm's-length contracts. We analyze all types of sales contracts in our 
reviews to validate proper value and deductions.
    The criteria that we will use to establish a royalty value under 
the default provision is the same basic criteria that we base all 
royalty values upon. Further, we specifically list these criteria in 
the coal regulations. Factors that we could consider if we decide that 
we will determine value for royalty purposes under the default 
provision are clearly delineated and may include, but would not be 
limited to, (1) the value of like-quality coal from the same mine, 
nearby mines, same region, or other regions, or washed in the same or 
nearby wash plant; (2) public sources of price or market information 
that we deem reliable, including but not limited to, the price of 
electricity; (3) information available to us and information reported 
to us, including but not limited to, on the Solid Minerals Production 
and Royalty Report (Form ONRR-4430); (4) costs of transportation or 
washing, if we determine that they are applicable; or (5) any other 
information that we deem relevant regarding the particular lease 
operation or the salability of the coal.
3. Determination of Coal Value for Royalty Purposes (Sec.  1206.254)
    Default: ONRR added a default valuation provision allowing us to 
value your coal under this section or any other provision in this 
subpart F. We address comments pertaining to the default provision, 
which we detail in Sec.  1206.253, in this Preamble.
4. Valuation Determination Requests (Sec.  1206.258)
    Guidance and Determinations: ONRR clarified how a lessee may 
request a valuation determination from us. We addressed comments 
pertaining to guidance and determinations in Sec.  1206.108 of this 
Preamble. For the reasons that we discussed in response to comments, we 
deleted the words ``or guidance'' from the title and paragraph (a) of 
this section.
5. General Transportation Allowance Requirements (Sec.  1206.260)
    This section contains the requirements of the previous Sec.  
1206.261. This section also consolidates provisions applicable to both 
arm's-length and non-arm's-length transportation in the previous 
regulations and clarifies that you do not need our approval to report a 
transportation allowance for arm's-length or non-arm's-length 
transportation costs that you incur. Paragraph (c) explains in which 
circumstances you cannot take an allowance. Finally, we added paragraph 
(g), containing the default provision, which includes the requirements 
of previous paragraphs 1206.262(a)(2) and 1206.262(a)(3) regarding 
additional consideration, misconduct, and breach of the duty to market.
    Fifty-percent allowance cap: In the preamble of the proposed rule, 
we solicited comments on whether or not we should impose a 50-percent 
cap on coal transportation allowances.
    Public Comment: ONRR received several comments from public interest 
groups, the public, and one individual commenter maintaining that ONRR 
should cap or eliminate transportation allowances. Commenters 
supporting a 50-percent cap on transportation suggested that coal 
transportation allowances should be in line with the oil and gas 
transportation regulations. Several commenters suggested that ONRR 
should use an index or a published common carrier rate to establish the 
cost of transportation.
    Local businesses, companies, and industry trade groups opposed any 
type of cap on transportation allowances, stating that the costs of 
transporting coal are significant and the corresponding deductions are 
critical to maintain economic operations. Companies and industry trade 
groups argued that transportation allowances were the best way to 
establish the value of coal at the mine where the lessee sells coal in 
a distant market. Further, industry trade groups opposed using standard 
schedules for transportation allowances, stating that transporting coal 
is subject to unpredictable market variables and that ONRR should use 
actual costs.
    ONRR Response: After careful review of the comments, we will not 
impose a cap on transportation allowances at this time. We consider the 
reasonable, actual cost of transporting coal to be the best method for 
establishing an appropriate allowance when determining coal royalty 
value and will continue to implement this regulation.
    Written contracts: ONRR added a new provision stating that we will 
determine transportation allowances if lessees do not have a written 
contract for the arm's-length transportation of coal. We addressed 
comments pertaining to this issue, which we discussed in Sec.  
1206.104, in this Preamble.
    Default provision: ONRR added a default provision under which we 
may determine your transportation allowance under Sec.  1206.254 if (1) 
there is misconduct by or between the contracting parties, (2) the 
total consideration the lessee or its affiliate pays under an arm's-
length contract does not reflect the reasonable cost of transportation 
or because the lessee breached its duty to market coal for the mutual 
benefit of the lessee and the lessor by transporting coal at a cost 
that is unreasonably high, or (3) ONRR cannot determine if the lessee 
properly calculated a transportation allowance for any reason.
    Public Comment: Many of the comments from industry and industry 
trade groups regarding ONRR's potential use of the default provision, 
as it relates to the transportation of coal, are similar to those put 
forth for determining the allowances for oil or gas. Commenters believe 
that ONRR's use of a 10-percent variance above the highest reasonable 
measure of transportation standard is arbitrary, capricious, and 
unnecessary. Some commenters representing States' interests, however, 
believe that ONRR should include stronger regulatory language that 
requires ONRR to use the default method when the 10-percent variance is 
reached.
    ONRR Response: Please refer to our response to Sec.  1206.253 for a 
more detailed explanation of the default provision. The default 
provision is a well-conceived valuation tool that the Secretary will 
use to determine the correct amount of transportation deductions for 
coal. The 10-percent variance that we may use in our analysis of 
transportation transactions is nothing more than a tolerance to help 
determine a proper transportation allowance. In past and current 
compliance reviews and audit procedures, we have always used tolerances 
to reflect what is reasonable in any given market, at any given time. 
Our use of the default provision under the final valuation regulations 
is a continuation of current practice. We will continue to determine 
transportation costs that industry incurs on their own merits based on 
reasonable actual costs allowable under the regulations.
    Misconduct: ONRR added a new definition for the term 
``misconduct.'' We addressed comments pertaining to this issue, which 
we detail in Sec.  1206.20, in this Preamble.
6. Determining Non-Arm's-Length Transportation (Sec.  1206.262)
    ONRR intended for the paragraphs addressing the BBB bond rate to be 
the same as those in the oil and gas provisions. Therefore, we deleted 
paragraph (k)(3).

[[Page 43357]]

7. General Washing Allowance Requirements (Sec.  1206.267)
    ONRR added this section to contain the requirements of previous 
Sec.  1206.258. We clarified that you do not need prior approval for 
reporting an allowance for the costs to wash coal and you must allocate 
washing costs attributable to each Federal lease. We also added that 
you cannot take an allowance for washing lease production that is not 
royalty-bearing, can only claim the costs of washing as an allowance 
when you sell the washed coal, and added the same default provision as 
that for the Federal oil, gas, and coal transportation regulations 
discussed in Sec. Sec.  1206.110(f), 1206.152(g), and 1206.260(g).
    Fifty-percent washing allowance cap: In the preamble of the 
proposed rule, ONRR solicited comments on whether we should impose a 
50-percent cap on washing allowances.
    Public Comment: ONRR received several comments from public interest 
groups, the general public, and a State maintaining that ONRR should 
not allow any deductions for the costs of washing coal because they are 
costs to place the coal in to marketable condition. Some of those same 
commenters, however, stated that, if ONRR continues to allow the costs 
of washing coal, they support a 50-percent cap on those allowances. 
Some commenters suggested that an ONRR-created index should be 
developed to determine washing allowances, while others similarly 
stated that, if ONRR does allow the washing allowances, the allowances 
should be fixed in advance.
    An industry trade group opposed any cap on washing allowances, 
stating that the costs of washing coal are significant and the 
corresponding deductions are critical to maintain economic operations. 
It also stated that the costs of washing coal must be deductible from 
gross proceeds in order to maintain royalty on the value of coal at the 
lease rather than on an inflated basis.
    ONRR Response: After careful review of the comments, we will not 
impose a cap on washing allowances at this time and will continue the 
practice of allowing the deduction of the costs of washing coal. The 
reasonable, actual cost of coal washing is the preferred method to 
arrive at an appropriate allowance when determining coal royalty value, 
and we will continue to implement this regulation.
    Written contracts: ONRR added a new provision stating that we will 
determine washing allowances if lessees do not have a written contract 
for the arm's-length washing of coal. We addressed comments pertaining 
to this issue, which we detail in Sec.  1206.104, in this Preamble.
    Default provision: ONRR added a default provision under which we 
may determine your washing allowance under Sec.  1206.254 if (1) there 
is misconduct by or between the contracting parties; (2) the total 
consideration that the lessee or its affiliate pays under an arm's-
length contract does not reflect the reasonable cost of washing or 
because the lessee breached its duty to market coal for the mutual 
benefit of the lessee and the lessor by washing coal at a cost that is 
unreasonably high; or (3) we cannot determine if the lessee properly 
calculated a washing allowance for any reason.
    Public Comment: Many of the comments from industry and industry 
trade associations regarding ONRR's potential use of the default 
provision, as it relates to the washing of coal, are similar to those 
put forth for determining the allowances for oil or gas. Commenters 
believe that ONRR's use of a 10-percent variance above the highest 
reasonable measure of washing standard is arbitrary, capricious, and 
unnecessary. Some commenters representing States' interests, however, 
believe that ONRR should include stronger regulatory language that 
requires ONRR to use the default method when the 10-percent variance is 
reached.
    ONRR Response: We provide a detailed response to the default 
provision topic in this Preamble under Sec.  1206.253. The default 
provision is a well-conceived valuation tool that the Secretary will 
use to determine the correct amount of washing deductions for coal. The 
10-percent variance that we may use in our analysis of washing 
transactions is nothing more than a tolerance to help determine a 
proper washing allowance. In past and current compliance reviews and 
audit procedures, we have always used tolerances to reflect what is 
reasonable in any given market, at any given time. Our use of the 
default provision under the final valuation regulations is a 
continuation of current practice. We will continue to determine washing 
costs that industry incurs on their own merits based on reasonable, 
actual costs allowable under the regulations.
8. Determining Non-Arm's-Length Washing (Sec.  1206.269)
    ONRR intended for the paragraphs addressing the BBB bond rate to be 
the same as those in the oil and gas provisions. Therefore, we deleted 
paragraph (k)(3).

E. Specific Comments on 30 CFR Part 1206--Product Valuation, Subpart 
J--Indian Coal

1. Purpose and Scope (Sec.  1206.450)
    ONRR replaced the term ``Indian allottee'' with ``individual Indian 
mineral owner.'' We made no other substantive changes to this section.
    Public Comment: A Tribe proposed adding language that clarifies 
that an operating agreement between the lessor and lessee is also 
considered a lease.
    ONRR Response: We clearly defined the term ``lease'' in Sec.  
1206.20 and find it unnecessary to add additional language here.
2. Valuation Determination Requests (Sec.  1206.458)
    Guidance and Determinations: Under paragraph (a), a lessee may 
request a valuation determination or guidance from ONRR regarding any 
coal produced. Paragraph (a) provides that the lessee's request for a 
determination must (1) be in writing, (2) identify all leases involved, 
(3) identify all interest owners in the leases, (4) identify the 
operator(s) for those leases, and (5) explain all relevant facts. In 
addition, under paragraph (a), a lessee must provide (1) all relevant 
documents, (2) its analysis of the issue(s), (3) citations to all 
relevant precedents (including adverse precedents), and (4) its 
proposed valuation method.
    In response to a lessee's request for a determination, we may (1) 
decide that we will issue guidance, (2) inform the lessee in writing 
that we will not provide a determination or guidance, or (3) request 
that the ASPMB issue a determination.
    Paragraphs (b)(3)(i) and (ii) identify situations in which ONRR and 
the Assistant Secretary typically do not provide a determination or 
guidance, including, but not limited to, requests for guidance on 
hypothetical situations and matters that are the subject of pending 
litigation or administrative appeals.
    Under paragraph (c)(1), a determination that ASPMB signs binds both 
the lessee and ONRR unless the Assistant Secretary modifies or rescinds 
the determination.
    Public Comment: A Tribe proposed adding language to paragraph 
(b)(1) stating that ONRR will consult with the Indian Tribe prior to 
issuing a decision.
    ONRR Response: We routinely consult with Tribes and find it 
unnecessary to add language to this paragraph.
    We addressed additional comments pertaining to guidance and 
determinations in Sec.  1206.108. For the

[[Page 43358]]

reasons discussed in response to comments, we deleted the words, ``or 
guidance'' from the title and paragraph (a) of this section.
3. Determination of Non-Arm's-Length Transportation (Sec.  1206.462)
    ONRR intended for the paragraphs addressing the BBB bond rate to be 
the same as those in the oil and gas provisions. Therefore, we deleted 
paragraph (k)(3).
4. Determination of Arm's-Length Washing (Sec.  1206.467)
    Default: ONRR addressed comments pertaining to the default 
provision for Federal coal, which we discuss in Sec.  1206.267, in this 
Preamble.
5. Determination of Non-Arm's-Length Washing (Sec.  1206.469)
    ONRR intended for the paragraphs addressing the BBB bond rate to be 
the same as those in the oil and gas provisions. Therefore, we deleted 
paragraph (k)(3).

                     Derivation Table for Part 1206
------------------------------------------------------------------------
 The requirements of section:          Are derived from section:
------------------------------------------------------------------------
                                Subpart C
------------------------------------------------------------------------
1206.20......................  1206.101; 1206.151; 1206.251; 1206.451.
1206.101.....................  1206.102.
1206.102.....................  1206.103.
1206.103.....................  1206.104.
1206.106.....................  1206.105.
1206.107.....................  1206.106
1206.108.....................  1206.107.
1206.109.....................  1206.108.
1206.110.....................  1206.109.
1206.111.....................  1206.110.
1206.112.....................  1206.111.
1206.113.....................  1206.112
1206.114.....................  1206.113.
1206.115.....................  1206.114.
1206.116.....................  1206.115.
1206.117.....................  1206.116.
1206.118.....................  1206.117.
------------------------------------------------------------------------
                                Subpart D
------------------------------------------------------------------------
1206.140.....................  1206.150.
1206.141(a)(1)-(3)...........  1206.152(a)(1).
1206.141(b)(1)-(3)...........  1206.152(a)(2).
1206.141(b)(4)...............  1206.152(b)(1)(iv).
1206.142(a)(4)...............  1206.153(a)(1).
1206.142(b)..................  1206.153(a)(2).
1206.142(c)..................  1206.153(b)(1)(i).
1206.143(a)(1) and (b).......  1206.152(b)(1)(ii); 1206.153(b)(1)(ii).
1206.143(a)(2)...............  1206.152(f); 1206.153(f).
1206.143(c)..................  1206.152(b)(1)(iii); 1206.153(b)(1)(iii).
1206.144.....................  1206.152(c)(1)-(3); 1206.153(c)(1)-(3).
1206.145.....................  1206.152(e)(1) and (2); 1206.153(e)(1)
                                and (2); 1206.157(c)(1)(ii) and
                                (c)(2)(iii); 1206.159(c)(1)(ii) and
                                (c)(2)(iii).
1206.146.....................  1206.152(i); 1206.153(i).
1206.147.....................  1206.152(k); 1206.153(k).
1206.148.....................  1206.152(g); 1206.153(g).
1206.149.....................  1206.152(l); 1206.153(l).
1206.150.....................  1206.154.
1206.151.....................  1206.155.
1206.152(a)..................  1206.156(a).
1206.152(b)..................  1206.156(b); 1206.157(a)(2) and (b)(3).
1206.152(c)(1)...............  1206.157(a)(2) and (b)(4).
1206.152(f)..................  1206.157(a)(4).
1206.153(b)..................  1206.157(f).
1206.153(c)..................  1206.157(g).
1206.154(a)..................  1206.157(b).
1206.154(e)-(h)..............  1206.157(b)(2)(i)-(iii).
1206.154(i)..................  1206.157(b)(2)(iv).
1206.154(i)(3)...............  1206.157(b)(2)(v).
1206.155.....................  1206.157(c)(1)(i), (ii).
1206.156.....................  1206.157(c)(2)(i)-(iv).
1206.157(a)(1) and (c).......  1206.156(d).
1206.157(a)(2) and 1206.158..  1206.157(e).
1206.159(a)(1)...............  1206.158(a).
1206.159(b)..................  1206.158(b).
1206.159(c)(1) and (2).......  1206.158(c)(1) and (2).
1206.159(d)..................  1206.158(d)(1).
1206.160.....................  1206.159(a).
1206.161.....................  1206.159(b).

[[Page 43359]]

 
1206.162.....................  1206.159(c)(1).
1206.163.....................  1206.159(c)(2).
1206.164.....................  1206.159(d).
1206.165.....................  1206.159(e).
------------------------------------------------------------------------
                                Subpart F
------------------------------------------------------------------------
1206.250.....................  1206.250.
1206.251.....................  1206.254; 1206.255; 1206.260.
1206.252(d)..................  1206.258(a); 1206.261(b).
1206.260(a)(1) and (b).......  1206.261(a).
1206.260(c)(2)...............  1206.261(a)(2).
1206.260(d)..................  1206.261(c)(3).
1206.260(e)..................  1206.261(c)(1), (c)(2), and (e).
1206.260(f)..................  1206.262(a)(4).
1206.260(g)..................  1206.262(a)(2) and (a)(3).
1206.261.....................  1206.262(a)(1).
1206.262.....................  1206.262(b).
1206.263.....................  1206.262(c)(1).
1206.264.....................  1206.262(c)(2).
1206.265.....................  1206.262(d).
1206.266.....................  1206.262(e).
1206.267(a)..................  1206.258(a).
1206.267(b)(2)...............  1206.258(c); 1206.260.
1206.267(c)..................  1206.259(a)(4).
1206.267(d)..................  1206.259(a)(2) and (a)(3).
1206.267(e)..................  1206.258(e).
1206.268.....................  1206.259(a)(1).
1206.269.....................  1206.259(b).
1206.270.....................  1206.259(c)(1).
1206.271.....................  1206.259(c)(2).
1206.272.....................  1206.259(d).
1206.273.....................  1206.259(e).
------------------------------------------------------------------------
                                Subpart J
------------------------------------------------------------------------
1206.450.....................  1206.450.
1206.451.....................  1206.453; 1206.454; 1206.459.
1206.460.....................  1206.461(a)(1).
1206.463.....................  1206.461(c).
------------------------------------------------------------------------

III. Procedural Matters

1. Summary Cost and Royalty Impact Data

    We estimated the costs and benefits that this rule will have on all 
potentially affected groups: Industry, the Federal Government, Indian 
lessors, and State and local governments. These amendments that have 
cost impacts will result in an estimated annual increase in royalty 
collections. The sum of these amendments that have cost benefits are 
due to administrative cost savings to industry, not a decrease in 
royalties due. The net impact of these amendments is an estimated 
annual increase in royalty collections of between $71.9 million and 
$84.9 million. This net impact represents a slight increase of between 
0.8 percent and 1.0 percent of the total Federal oil, gas, and coal 
royalties that we collected in 2010. We also estimate that industry 
will experience reduced annual administrative costs of $3.61 million.
    Please note that, unless otherwise indicated, numbers in the 
following tables are rounded to three significant digits.
A. Industry
    The table below lists ONRR's low, mid-range, and high estimates of 
the costs, by component, that industry will incur in the first year. 
Industry will incur these costs in the same amount each year 
thereafter.

                                     Summary of Royalty Impacts to Industry
----------------------------------------------------------------------------------------------------------------
            Rule provision                     Low                Mid                High
-----------------------------------------------------------------------------------------------
Gas--to replace benchmarks
    Affiliate resale..................                 $0         $2,010,000         $4,030,000
    Index.............................         11,300,000         11,300,000         11,300,000
NGLs--to replace benchmarks
    Affiliate resale..................                  0            256,000            510,000
    Index.............................          1,200,000          1,200,000          1,200,000
Gas transportation limited to 50%.....          4,170,000          4,170,000          4,170,000
Processing allowance limited to 66\2/           5,440,000          5,440,000          5,440,000
 3\%..................................
POP contracts limited to 66\2/3\%                       0                  0                  0
 processing allowance.................
Extraordinary processing allowance....         18,500,000         18,500,000         18,500,000

[[Page 43360]]

 
BBB bond rate change for gas                    1,640,000          1,640,000          1,640,000
 transportation.......................
Eliminate deep water gathering........         17,400,000         20,500,000         23,600,000
Oil transportation limited to 50%.....          6,430,000          6,430,000          6,430,000
Oil and gas line losses...............          4,571,000          4,571,000          4,571,000
BBB bond rate change for oil                    2,380,000          2,380,000          2,380,000
 transportation.......................
Coal--to non-arm's-length netback & co-       (1,060,000)                  0          1,060,000
 op sales.............................
                                       -------------------------------------------------------------------------
    Total.............................         71,922,000         78,390,000         84,850,000
----------------------------------------------------------------------------------------------------------------
Note 1: Totals from this table and others in this analysis may not add due to rounding.
Note 2: Lessees may experience a one-time administrative cost to update their systems to comply with this rule.
  However, because a change would be unique to an individual lessee, ONRR was unable to quantify those one-time
  costs. Recognizing lessees may have to change their systems, we set the effective date of this rule to 180
  days from the date of publication.

    ONRR identified two rule changes that will benefit industry by 
reducing their administrative costs. The benefits that industry will 
realize for each of these components are as follows:

------------------------------------------------------------------------
                   Rule provision                         Benefit
-----------------------------------------------------------------------
Replace benchmarks--Gas & NGLs.....................           $247,000
Eliminate deep water gathering.....................          3,360,000
                                                    --------------------
    Total..........................................          3,610,000
------------------------------------------------------------------------

    The table below lists the overall economic impact to industry from 
the rule changes, based on the mid-range estimate of costs:

------------------------------------------------------------------------
                                                         Annual (cost)/
                     Description                         benefit amount
------------------------------------------------------------------------
Cost--All rule provisions............................      ($78,390,000)
Benefit--Administrative savings......................          3,610,000
Net cost or benefit to industry......................       (74,780,000)
------------------------------------------------------------------------

Cost--Using First Arm's-Length Sale to Value Non-Arm's-Length Sales of 
Federal Unprocessed Gas, Residue Gas, and Coalbed Methane

    As discussed above, we will replace the current benchmarks in 
Sec. Sec.  1206.152(c) (unprocessed gas) and 1206.152(c) (processed 
gas) with a methodology that uses the gross proceeds under the lessee's 
affiliate's first arm's-length sale to value gas for royalty purposes. 
The lessee also will have the option to elect to pay royalties based on 
a value using the monthly high index price, less a standard deduction 
for transportation.
    To perform this economic analysis, we first extracted royalty data 
that we collected on residue gas, unprocessed gas, and coalbed methane 
(product codes 03, 04, 39, respectively) for calendar year 2010. We 
chose calendar year 2010 because the Royalty-in-Kind (RIK) volumes were 
minimal due to the 2010 termination of the RIK program. In previous 
years, RIK volumes were substantial. Data from RIK production is not 
representative of industry sales, so we excluded any remaining RIK 
volumes from our analysis.
    We then extracted gas royalty data for non-arm's-length 
transactions reported with a sales type code of NARM. We also extracted 
gas royalty data for sales type code POOL because royalty reporters may 
also use this code to report non-arm's-length transactions. Based on 
our experience with auditing transactions that use sales type code 
POOL, we know that only a relatively small portion of them are non-
arm's-length. Therefore, we used only 10 percent of the POOL volumes in 
our economic analysis of the volumes of gas sold non-arm's-length.
    Based on our experience auditing production sold under non-arm's-
length contracts, we find that industry will incur a royalty increase 
in the range of 0 to 5 cents per MMBtu under our proposal to use the 
affiliate's first arm's-length resale to value gas production for 
royalty purposes. We created a range of potential royalty increases by 
assuming no royalty increase for the low estimate, 2.5 cents per MMBtu 
for the mid-range estimate, and 5 cents per MMBtu for the high 
estimate. We then multiplied the NARM volume and 10 percent of the POOL 
volume reported to us in 2010 by the potential royalty increases.
    The results that we provided below are an estimated cost to 
industry due to an annual royalty increase of between zero and 
approximately $8 million. We reduced this estimate by one-half to $4.03 
million, assuming lessees whose volumes represent 50 percent of the 
non-arm's-length sales will choose this option.

----------------------------------------------------------------------------------------------------------------
                                                                               Royalty increase ($)
                                                2010 MMBtu (non- -----------------------------------------------
                                                    rounded)                         Mid (2.5
                                                                   Low (0 cents)      cents)      High (5 cents)
----------------------------------------------------------------------------------------------------------------
NAL volume....................................       149,348,561              $0      $3,730,000      $7,470,000
10% of POOL volume............................        11,606,523               0         290,000         580,000
                                               -----------------------------------------------------------------
    Total.....................................       160,955,084               0       4,020,000       8,050,000
----------------------------------------------------------------------------------------------------------------
50% of non-arm's-length volumes.................................               0       2,010,000       4,030,000
----------------------------------------------------------------------------------------------------------------


[[Page 43361]]

Cost--Using Index Price Option to Value Non-Arm's-Length Sales of 
Federal Unprocessed Gas, Residue Gas, and Coalbed Methane

    To estimate the royalty impact of the index-based option, we 
calculated a monthly weighted average price net of transportation using 
NARM and 10 percent of the POOL gas royalty data from six major 
geographic areas with active index prices: The Green River Basin; San 
Juan Basin; Piceance and Uinta Basins; Powder River and Wind River 
Basins; Permian Basin; and Offshore Gulf of Mexico (GOM). These six 
areas account for approximately 95 percent of all Federal gas produced. 
To calculate the estimated impact, we performed the following steps:
    (1) Identified the Platts Inside FERC highest reported monthly 
price for the index price applicable to each area--Northwest Pipeline 
Rockies for Green River, El Paso San Juan for San Juan, Northwest 
Pipeline Rockies for Piceance and Uinta, Colorado Interstate Gas for 
Powder River and Wind River, El Paso Permian for Permian, and Henry Hub 
for GOM.
    (2) Subtracted the transportation deduction that we specified in 
the proposed rule from the highest index price that we identified in 
step (1).
    (3) Subtracted the average monthly net royalty price reported to us 
for unprocessed gas from the highest index price for the same month 
that we calculated in step (2).
    (4) Multiplied the royalty volume by the monthly difference that we 
calculated in step (3) to calculate a monthly royalty difference for 
each region.
    (5) Totaled the difference that we calculated in step (4) for the 
regions.
    Although the index-based methodology resulted in an annual increase 
in royalties due, the current average royalty prices reported to us 
were higher than the index-based option for three months in 2010.
    We estimate that the cost to industry due to this change will be an 
increase in royalty collections of approximately $11.3 million 
annually. This estimate represents a small average increase of 
approximately 3.6 percent or 14 cents per MMBtu, based on an annual 
royalty volume of 160,955,084 MMBtu (for NARM and 10 percent POOL 
reported sales type codes). Because this is the first time that we have 
offered this option, we don't know how many payors will choose it. We 
reduced this estimate by one-half, assuming lessees whose volumes 
represent 50 percent of the non-arm's-length sales will choose this 
option.

----------------------------------------------------------------------------------------------------------------
                    2010 Index analysis                          GOM gas          Other gas           Total
----------------------------------------------------------------------------------------------------------------
Current royalties (rounded to the nearest dollar).........      $167,291,148      $435,222,354      $602,513,502
Royalty under index option................................       180,000,000       445,000,000       625,000,000
Difference................................................        12,700,000         9,780,000        22,500,000
Per unit uplift ($/MMBtu).................................             0.297             0.083             0.140
% change..................................................              7.06              2.20              3.60
----------------------------------------------------------------------------------------------------------------
50% of non-arm's-length volumes...............................................................        11,300,000
----------------------------------------------------------------------------------------------------------------

Cost--Using First Arm's-Length Sale to Value Non-Arm's-Length Sales of 
Federal NGLs

    Like the valuation changes that we discussed above, for Federal 
unprocessed, residue, and coalbed methane gas valuation changes, this 
rule will value processed Federal NGLs based on the first arm's-length 
sale rather than the current benchmarks. The lessee also will have the 
option to pay royalties using an index-price value derived from an NGL 
commercial price bulletin, less a theoretical processing allowance that 
includes transportation and fractionation of the NGLs. We again used 
the 2010 NARM and POOL NGL data reported to us for this analysis.
    We performed the same analysis for valuation using the first arm's-
length sale for Federal unprocessed, residue, and coalbed methane gas, 
as we discussed above. We identified the non-arm's-length volumes that 
would qualify for this option (for NARM and 10 percent POOL reported 
sales type codes) and estimated a cents-per-gallon royalty increase. 
Based on our experience, the NGLs resale margin is, similar to gas, 
relatively small, ranging from zero to 3 cents per gallon. Thus, our 
estimated royalty increase is zero for the low, 1.5 cents per gallon 
for the mid-range, and 3 cents per gallon for the high range. The 
results provided below show a mid-range royalty increase of $256,000 
using these assumptions, and, again, we reduced them by one-half, 
assuming lessees whose volumes represent 50 percent of the non-arm's-
length sales will choose this option.

----------------------------------------------------------------------------------------------------------------
                                                                               Royalty increase ($)
                                                  2010 Gallons   -----------------------------------------------
                                                 (rounded to the                     Mid (1.5
                                                 nearest gallon)   Low (0 cents)      cents)      High (3 cents)
----------------------------------------------------------------------------------------------------------------
NAL volume....................................         6,170,341              $0         $92,600        $185,000
10% of POOL volume............................        27,913,486               0         419,000         837,000
                                               -----------------------------------------------------------------
    Total.....................................        34,083,827               0         512,000       1,020,000
----------------------------------------------------------------------------------------------------------------
50% of non-arm's-length volumes.................................               0         256,000         510,000
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------

Cost--Using Index Price Option to Value Non-Arm's-Length Sales of 
Federal NGLs

    Like the Federal unprocessed, residue, and coalbed methane gas 
changes that we discussed above, lessees also will have the option to 
pay royalties on Federal NGLs using an index-based value less a 
theoretical processing allowance that includes transportation and 
fractionation. We used the same 2010 NARM and POOL transaction data for 
NGLs for this analysis. We were unable to compare NGLs prices reported 
on Form ONRR-2014 to those in commercial price bulletins because prices 
that lessees report on Form ONRR-2014 are one

[[Page 43362]]

rolled-up price for all NGLs. Conversely, the bulletins price each NGL 
product (such as ethane and propane) separately. We based our analysis 
on the royalty changes that will result from the theoretical processing 
allowance proscribed under this new option.
    We chose a conservative number as a proxy for the processing 
allowance deduction that we will allow for this index option. To 
determine the cost of this option for NGLs, we calculated the 
difference between the average processing allowance reported on Form 
ONRR-2014 and the proxy allowance that we will allow under this option. 
That difference equaled an increase in value of approximately 7 cents 
per gallon. We then multiplied the total NAL volume of 34,083,827 
gallons reported to us by the 7 cents per gallon, for an estimated 
royalty increase of $2.4 million. We reduced this number by one-half 
under the assumption that 50 percent of lessees will choose this 
option, resulting in a total cost to industry of $1.2 million.

Benefit--Using Index Price Option to Value Non-Arm's-Length Federal 
Unprocessed Gas, Residue Gas, Coalbed Methane, and NGLs

    We expect that industry will benefit by realizing administrative 
savings if they choose to use the index-based option to value non-
arm's-length sales of Federal unprocessed gas, residue gas, coalbed 
methane, and NGLs. Lessees will know the price to use to value their 
production, saving the time that it currently takes to calculate the 
correct price based on the current benchmarks. They also will save time 
using the ONRR-specified transportation rate for gas and the ONRR-
specified processing allowance for NGLs, rather than having to 
calculate those values themselves.
    Of the lessees that we estimated will use this option, we estimated 
the index-based option will shorten the time burden per line reported 
by 50 percent to 1.5 minutes for lines that industry electronically 
submits and 3.5 minutes for lines that they manually submit. We used 
tables from the Bureau of Labor Statistics (BLS) (www.bls.gov/oes132011.htm) to estimate the hourly cost for industry accountants in 
a metropolitan area. We added a multiplier of 1.4 for industry 
benefits. The industry labor cost factor for accountants will be 
approximately $50.53 per hour = $36.09 [mean hourly wage] x 1.4 
[benefits cost factor]. Using a labor cost factor of $50.53 per hour, 
we estimate the annual administrative benefit to industry will be 
approximately $247,000.

----------------------------------------------------------------------------------------------------------------
                                                                              Estimated  lines
                                                            Time burden  per   reported  using   Annual  burden
                                                             line  reported     index  option         hours
                                                                                    (50%)
----------------------------------------------------------------------------------------------------------------
Electronic reporting (99%)................................           1.5 min           190,872             4,772
Manual reporting (1%).....................................           3.5 min             1,928               112
----------------------------------------------------------------------------------------------------------------
Industry labor cost/hour..................................  ................  ................            $50.53
----------------------------------------------------------------------------------------------------------------
    Total benefit to industry.............................  ................  ................          $247,000
----------------------------------------------------------------------------------------------------------------

Cost--Elimination of Transportation Allowances in Excess of 50 Percent 
of the Value of Federal Gas

    The previous Federal gas valuation regulations limited lessees' 
transportation allowances to 50 percent of the value of the gas unless 
they requested and received approval to exceed that limit. This rule 
eliminated the lessees' ability to exceed that limit. To estimate the 
costs associated with this change, we first identified all calendar 
year 2010 reported gas transportation allowances rates that exceeded 
the 50-percent limit. We then adjusted those allowances down to the 50-
percent limit and totaled that value to estimate the economic impact of 
this provision. The result was an annual estimated cost to industry of 
$4.17 million in additional royalties.

Cost--Elimination of Transportation Allowances in Excess of 50 Percent 
of the Value of Federal Oil

    The previous Federal oil valuation regulations limit lessees' 
transportation allowances to 50 percent of the value of the oil unless 
they request and receive approval to exceed that limit. This rule 
eliminates the lessees' ability to exceed that limit. To estimate the 
costs associated with this change, we first identified all calendar 
year 2010 reported oil transportation allowance rates that exceeded the 
50-percent limit. We then adjusted those allowances down to the 50-
percent limit and totaled that value to estimate the economic impact of 
this provision. The result was an annual estimated cost to industry of 
$6.43 million in additional royalties.

Cost--Elimination of Processing Allowances in Excess of 66\2/3\ Percent 
of the Value of the NGLs for Federal Gas

    The previous Federal gas valuation regulations limit lessees' 
processing allowances to 66\2/3\ percent of the value of the NGLs 
unless they request and receive approval to exceed that limit. This 
rule eliminates the lessees' ability to exceed that limit. To estimate 
the cost to industry associated with this change, we first identified 
all calendar year 2010 reported processing allowances greater than 
66\2/3\ percent. We then adjusted those allowances down to the 66\2/3\-
percent limit and totaled that value to estimate the economic impact of 
this provision. The result was an annual estimated cost to industry of 
$5.44 million in additional royalties.

Cost--POP Contracts now Subject to the 66\2/3\-percent Processing 
Allowance Limit for Federal Gas

    Lessees with POP contracts currently pay royalties based on their 
gross proceeds as long as they pay a minimum value equal to 100 percent 
of the residue gas. Under this rule, we also will not allow lessees 
with POP contracts to deduct more than the 66\2/3\ percent of the value 
of the NGLs. For example, a lessee with a 70-percent POP contract 
receives 70 percent of the value of the residue gas and 70 percent of 
the value of the NGLs. The 30 percent of each product that the lessee 
gives up to the processing plant in the past cannot, when combined, 
exceed an equivalent value of 100 percent of the NGLs' value. Under 
this rule, the combined value of each product that the lessee gives up 
to the processing plant cannot exceed two-thirds of the NGLs' value.
    Lessees report POP contracts to ONRR using sales type code APOP for 
arm's-length POP contracts and NPOP for non-arm's-length POP contracts. 
Because lessees report APOP sales as unprocessed gas, there are no 
reported processing allowances for us to analyze, and we cannot 
determine the breakout

[[Page 43363]]

between residue gas and NGLs. Lessees do report residue gas and NGLs 
separately for NPOPs. However, NPOP volumes constitute only 0.02 
percent of all of the natural gas royalty volumes that lessees report 
to us. We deemed the NPOP volume to be too low to adequately assess the 
impact of this provision on both APOP and NPOP contracts.
    Therefore, we decided to examine all reported calendar year 2010 
onshore residue gas and NGLs royalty data and assumed that it was 
processed and that lessees paid royalties as if they sold the residue 
gas and NGLs under a POP contract. We restricted our analysis to 
residue gas and NGLs volumes produced onshore because we are not aware 
of any offshore POP contracts. We first totaled the residue gas and 
NGLs' royalty value for calendar year 2010 for all onshore royalties. 
We then assumed that these royalties were subject to a 70-percent POP 
contract. Based on our experience, a 70/30 split is typical for POP 
contracts. We calculated 30 percent of both the value of residue gas 
and NGLs to approximate a theoretical 30-percent processing deduction. 
We then compared the 30-percent total of residue gas and NGL values to 
66\2/3\ percent of the NGL's value (the maximum allowance under this 
rule). The table below summarizes these calculations, which we rounded 
to the nearest dollar:

----------------------------------------------------------------------------------------------------------------
                                                           2010 Royalty
                                                               value               70%                 30%
----------------------------------------------------------------------------------------------------------------
Residue gas............................................      $602,194,031         $421,535,822      $180,658,209
NGLs...................................................       506,818,440          354,772,908       152,045,532
                                                        --------------------------------------------------------
    Total..............................................     1,109,012,471          776,308,730       332,703,741
----------------------------------------------------------------------------------------------------------------
66.67% Limit...........................................       337,878,960   (506,818,440 x \2/  ................
                                                                                           3\)
----------------------------------------------------------------------------------------------------------------

    Our analysis shows that the theoretical processing deduction for 30 
percent of the value of residue gas and NGLs ($333 million) under our 
assumed onshore POP contract allowance will not exceed the 66\2/3\-
percent cap ($338 million) under this rule and, thus, we estimate that 
this change will be revenue-neutral.

Cost--Termination of Policy Allowing Transportation Allowances for Deep 
Water Gathering Systems for Federal Oil and Gas

    The Deep Water Policy that we discuss above allowed companies to 
deduct certain expenses for subsea gathering from their royalty 
payments, even though those costs do not meet our definition of 
transportation. This final rule rescinds and supersedes the Deep Water 
Policy, and lessees will pay royalties under these valuation 
regulations applicable to Federal oil and gas transportation 
allowances, prospectively. To analyze the cost impact to industry of 
rescinding this policy, we used data from BSEE's ArcGIS Technical 
Information Management System database to estimate that 113 subsea 
pipeline segments serving 108 leases currently qualify for an allowance 
under the policy. We assumed that all segments were the same--in other 
words, we did not take into account the size, length, or type of 
pipeline. We also considered only pipeline segments that were in active 
status and leases in producing status for our analysis. To determine a 
range (shown in the tables below as low, mid, and high estimates) for 
the cost to industry, we estimated a 15-percent error rate in our 
identification of the 113 eligible pipeline segments, resulting in a 
range of 96 to 130 eligible pipeline segments.
    Historical ONRR audit data is available for 13 subsea gathering 
segments serving 15 leases covering time periods from 1999 through 
2010. We used these data to determine an average initial capital 
investment in pipeline segments. We used the initial capital investment 
amount to calculate depreciation and a return on undepreciated capital 
investment (also known as the Return on Investment or ROI) for the 
eligible pipeline segments. We calculated depreciation using a 
straight-line depreciation schedule based on a 20-year useful life of 
the pipeline. We calculated ROI using 1.0 times the average BBB Bond 
rate for January 2012, which was the most recent full month of data 
when we performed this analysis. We based the calculations for 
depreciation and ROI on the first year when a pipeline was in service.
    From the same audit data, we calculated an average annual Operating 
and Maintenance (O&M) cost. We increased the O&M cost by 12 percent to 
account for overhead expenses. Based on experience and audit data, we 
assumed that 12 percent is a reasonable increase for overhead. We then 
decreased the total annual O&M cost per pipeline segment by 9 percent 
because an average of 9 percent of offshore wellhead oil and gas 
production is water, which is not royalty bearing. Finally, we used an 
average royalty rate of 14 percent, which is the volume weighted 
average royalty rate for all non-Section 6 leases in the GOM. Based on 
these calculations, the average annual allowance per pipeline segment 
is approximately $226,000. This represents the estimated amount per 
pipeline segment that we will no longer allow a lessee to take as a 
transportation allowance based on our rescission of the Deep Water 
Policy in this rule.
    The total cost to industry will be the $226,000 annual allowance 
per pipeline segment that we will disallow under this rule times the 
number of eligible segments. To calculate a range for the total cost, 
we multiplied the average annual allowance by the low (96), mid (113), 
and high (130) number of eligible segments. The low, mid, and high 
annual allowance estimates that we will disallow are $21.8 million, 
$25.6 million, and $29.5 million, respectively.
    Of currently eligible leases, 42 out of 108, or about 40 percent, 
qualify for deep water royalty relief. However, due to varying lease 
terms, royalty relief programs, price thresholds, volume thresholds, 
and other factors, we estimated that only half of the 42 leases 
eligible for royalty relief (20 percent) actually received royalty 
relief. Therefore, we decreased the low, mid, and high estimated annual 
cost to industry by 20 percent. The table below shows the estimated 
royalty impact of this section of this rule based on the allowances 
that we will no longer allow under this rule.

[[Page 43364]]



----------------------------------------------------------------------------------------------------------------
                                                                Low                Mid                High
----------------------------------------------------------------------------------------------------------------
Estimated royalty impact...............................       $17,400,000        $20,500,000        $23,600,000
----------------------------------------------------------------------------------------------------------------

Benefit--Termination of Policy Allowing Transportation Allowances for 
Deep Water Gathering Systems for Offshore Federal Oil and Gas

    We estimate that the elimination of transportation allowances for 
deep water gathering systems will provide industry with an 
administrative benefit because they will no longer have to perform this 
calculation. The cost to perform this calculation is significant 
because industry has often hired outside consultants to calculate their 
subsea transportation allowances. Using this information, we estimated 
that each company with leases eligible for transportation allowances 
for deep water gathering systems will allocate one full-time employee 
annually to perform this calculation if they use consultants or perform 
the calculation in-house. We used the BLS to estimate the hourly cost 
for industry accountants in a metropolitan area [$36.09 mean hourly 
wage] with a multiplier of 1.4 for industry benefits to equal 
approximately $50.53 per hour [$36.09 x 1.4 = $50.53]. Using this labor 
cost per hour, we estimate that the annual administrative benefit to 
industry will be approximately $3,360,000.

----------------------------------------------------------------------------------------------------------------
                                               Annual burden                       Companies        Estimated
                                                 hours per      Industry labor     reporting        benefit to
                                                  company         cost/hour     eligible leases      industry
----------------------------------------------------------------------------------------------------------------
Deep water Gathering........................           2,080           $50.53               32       $3,360,000
----------------------------------------------------------------------------------------------------------------

Cost--Elimination of Extraordinary Cost Gas Processing Allowances for 
Federal Gas

    As we discussed above, we eliminated the provision in the previous 
regulations that allow a lessee to request an extraordinary processing 
cost allowance and to terminate any extraordinary cost processing 
allowances that we previously granted. We granted two such approvals in 
the past, so we know the lease universe that is claiming this allowance 
and were able to retrieve the processing allowance data that lessees 
deducted from the value of residue gas produced from the leases. We 
then calculated the annual total processing allowance that lessees have 
claimed for 2007 through 2010 for the leases at issue. We then averaged 
the yearly totals for those four years to estimate an annual cost to 
industry of $18.5 million in increased royalties.

Cost--Decrease Rate of Return Used to Calculate Non-Arm's-Length 
Transportation Allowances From 1.3 to 1 Times the Standard and Poor's 
BBB Bond Rate for Federal Oil and Gas

    For Federal oil transportation, we do not maintain or request data 
identifying if transportation allowances are arm's-length or non-arm's-
length. However, based on our experience, a large portion of GOM oil is 
transported through lessee-owned pipelines. In addition, many onshore 
transportation allowances include costs of trucking and rail, and, most 
likely, this change will not impact those. Therefore, to calculate the 
costs associated with this change, we assumed that 50 percent of the 
GOM transportation allowances are non-arm's-length and 10 percent of 
transportation allowances everywhere else (onshore and offshore other 
than the GOM) are non-arm's-length. We also assumed that, over the life 
of the pipeline, allowance rates are made up of one-third rate of 
return on undepreciated capital investment, one-third depreciation 
expenses, and one-third operation, maintenance, and overhead expenses. 
These are the same assumptions that we made when analyzing changes to 
both the Federal oil and Federal gas valuation rules in 2004.
    In 2010, the total oil transportation allowances that Federal 
lessees deducted were approximately $60 million from the GOM and $11 
million from everywhere else. Based on these totals and our assumptions 
about the allowance components, the portion of the non-arm's-length 
allowances attributable to the rate of return will be approximately 
$10,000,000 for the GOM ($60,000,000 x \1/3\ x 50% = $10,000,000) and 
$367,000 ($11,000,000 x \1/3\ x 10% = $367,000) for the rest of the 
country. Therefore, we estimate that decreasing the basis for the rate 
of return by 23 percent will result in decreased yearly oil 
transportation allowance deductions of approximately $2,380,000 
($10,367,000 x 0.23 = $2,380,000). Thus, we estimate that the net cost 
to industry as a result of this change will be an approximately 
$2,380,000 increase in royalties due.
    With respect to Federal gas, like oil, we do not maintain or 
request information on whether gas transportation allowances are arm's-
length or non-arm's-length. However, unlike oil, it is not common for 
GOM gas to be transported through lessee-owned pipelines. Therefore, we 
assumed that only 10 percent of all gas transportation allowances are 
non-arm's-length and made no distinction between the GOM and everywhere 
else. All other assumptions for natural gas are the same as those we 
made for oil above.
    In 2010, the total gas transportation allowances that Federal 
lessees deducted were approximately $214 million. Based on that total 
and our assumptions regarding the makeup of the allowance components, 
the portion of the non-arm's-length allowances attributable to the rate 
of return will be approximately $7.13 million ($214,000,000 x \1/3\ x 
10% = $7,130,000). Therefore, we estimate that decreasing the basis for 
the rate of return by 23 percent will result in decreased yearly gas 
transportation allowance deductions of approximately $1.64 million 
($7.13 million x 0.23). That is, the net increased cost to industry, 
based on this change, will be approximately $1,640,000 in additional 
royalties.

Cost--Allow a Rate of Return on Reasonable Salvage Value for Federal 
Oil, Gas, and Coal

    For Federal oil and gas, after a transportation system or a 
processing plant has been depreciated to its reasonable salvage value, 
we will allow a lessee a return on that reasonable salvage value of the 
transportation system or processing plant as long as the lessee uses 
that system or plant for its Federal oil or gas production. We 
estimated that the economic impact on industry will be small because we 
will continue the requirements of the previous regulations that a 
lessee must base depreciation of a system or plant

[[Page 43365]]

upon the useful life of the equipment or the expected life of the 
reserves that the system or plant served. Thus, when properly 
established, the depreciation schedule should reflect the useful life 
of the system or plant, and we will not expect a lessee to continue to 
use a system or plant for periods significantly longer than the period 
reflected by the depreciation schedule that the lessee established for 
royalty purposes. This assumption is true, especially if the lessee did 
not make additional capital expenditures that extended the life of the 
system or plant. In that case, the lessee should have extended the 
depreciation schedule to reflect the extended life of the system or 
plant, and, possibly, the salvage value, itself. In other words, the 
vast majority of systems will not depreciate to salvage value while 
royalty is being paid because the system still has a useful life while 
production occurs. Thus, there will not be any costs to industry 
associated with this change.
    With respect to Federal coal, the royalty impact for coal will be 
equally small for the same reasons that we mentioned above.

Cost--Disallow Line Loss as a Component of Arm's-Length and Non-Arm's-
Length Oil and Gas Transportation

    We also will eliminate the current regulatory provision allowing a 
lessee to deduct costs of pipeline losses, both actual and theoretical, 
when calculating non-arm's-length transportation allowances. For this 
analysis, we assumed that pipeline losses are 0.2 percent of the volume 
transported through the pipeline, based on a survey of pipeline tariff. 
This 0.2 percent of the volume transported also equates to 0.2 percent 
of the value of the Federal royalty volume of oil and gas production 
transported.
    For Federal oil produced in calendar year 2010, the total value of 
the Federal royalty volume subject to transportation allowances was 
$3,796,827,823 in the GOM and $1,204,177,633 everywhere else. Using our 
previous assumption that 50 percent of GOM and 10 percent of everywhere 
else's transportation allowances are non-arm's-length, we estimated 
that the value of the line loss will be $4.04 million, as we detailed 
in the table below. Therefore, the annual cost to industry will be 
approximately $4.04 million in additional royalties.

                                          Oil Line Loss Royalty Impact
----------------------------------------------------------------------------------------------------------------
                                                           Royalty value      Line loss (%)     Royalty increase
----------------------------------------------------------------------------------------------------------------
50% of GOM royalty value...............................     $1,898,413,912                0.2         $3,800,000
10% of everywhere else royalty value...................        120,417,763                0.2            241,000
                                                        --------------------------------------------------------
    Total..............................................  .................  .................          4,040,000
----------------------------------------------------------------------------------------------------------------

    For Federal gas produced in calendar year 2010, the royalty value 
of the Federal gas royalty volume subject to transportation allowances 
was $2,656,843,158. Using our previous assumption that 10 percent of 
Federal gas transportation allowances are non-arm's-length, we 
estimated that the value of the line loss will be $531,000. Therefore, 
the annual cost to industry will be approximately $531,000 in increased 
royalties.

                                          Gas Line Loss Royalty Impact
----------------------------------------------------------------------------------------------------------------
                                                           Royalty value      Line loss (%)     Royalty increase
----------------------------------------------------------------------------------------------------------------
10% of royalty value...................................       $265,684,316                0.2           $531,000
----------------------------------------------------------------------------------------------------------------

    The total estimated royalty increase for both oil and gas due to 
this change will be $4.57 million [$4,040,000 (oil) + $531,000 (gas) = 
$4,571,000].

Cost--Depreciating Oil Pipeline Assets Only Once

    We will allow depreciation of oil pipeline assets only one time. 
Under the previous valuation regulations for Federal oil, if an oil 
pipeline was sold, we allowed the purchasing company to include the 
purchase price to establish a new depreciation schedule and, in 
essence, depreciate the same piece of pipe twice or more if it was sold 
again. Under this final rule, we allow depreciation only once. In 
theory, this change can result in additional royalties. However, based 
on our experience monitoring the oil markets, we find that the sale of 
oil pipeline assets is rare, and we are not aware of any such sales in 
the last five calendar years. We are also not aware of any planned 
future sales of oil pipelines that this rule change will impact. 
Therefore, although there will be a cost to industry under this rule, 
we cannot quantify the cost at this time.

Cost--Using First Arm's-Length Sale to Value Non-Arm's-Length Sales of 
Federal Coal and Sales of Federal Coal Between Coal Cooperatives and 
Coal Cooperative Members and Between Coal Cooperative Members

    We discuss this cost in the next section.
    Cost--Using Sales of Electricity to Value Non-Arm's-Length Sales of 
Federal Coal and Sales of Federal Coal Between Coal Cooperatives and 
Coal Cooperative Members and Between Coal Cooperative Members
    In our experience, non-arm's-length sales of Federal coal that is 
then resold at arm's-length represent a small fraction of all coal 
sales. Under the previous valuation regulations, such sales result in 
royalty values equivalent to values that result under the regulation at 
Sec.  1206.252(a) based on arm's-length resale prices. Thus, we 
estimated that there will be no royalty effect for these types of 
sales. In other words, there is no cost to lessees who produce Federal 
coal due to this valuation change in this rule.
    The remaining non-arm's-length dispositions of Federal coal 
(including lessees, their affiliates, coal cooperatives, and members of 
coal cooperatives) are when the lessee, its affiliate, coal 
cooperatives, or members of coal cooperatives consume(s) the Federal 
coal produced to generate electricity. These dispositions typically 
constitute from about one to two percent

[[Page 43366]]

of royalties paid on Federal coal produced.
    Under this rule, a lessee, its affiliates, a coal cooperative, and 
a member of a coal cooperative generally will base the royalty value of 
such sales on the sales value of the electricity, less costs to 
generate and, in some cases, transmit the electricity to the buyers, 
and less applicable coal washing and transportation costs. We have 
limited experience determining lease product royalty values using the 
method under Sec.  1206.252(b)(1). Therefore, to perform an economic 
analysis, we first determined the average royalties paid to us in 
calendar years 2009 through 2011 for these Federal coal dispositions. 
Based on our experience with other dispositions of Federal coal, we 
estimated that, at most, royalty values under this rule will increase 
or decrease by 10 percent, compared to royalty values that we 
determined under previous regulations. Using these assumptions, we 
estimated the annual average royalty impact and, thus, the cost or 
benefit to industry from this rule.
    Our method is the same for estimating the royalty impact of using 
sales of electricity to value non-arm's-length sales of Federal coal, 
sales of Federal coal between coal cooperatives and coal cooperative 
members, and sales between coal cooperative members. Therefore, the 
estimated royalty impact will be a combined figure covering all such 
valuation of Federal coal under this rule. Accordingly, we estimated 
that the combined average annual royalty impacts for these coal 
dispositions will range from a royalty decrease of $1.06 million 
(benefit) to a royalty increase of $1.06 million (cost).

Cost--Using Default Provision to Value Non-Arm's-Length Sales of 
Federal Coal in Lieu of Sales of Electricity

    If we were unable to establish royalty values of Federal coal using 
the sales value of electricity generated from coal produced, royalty 
value will be based on a method that the lessee proposes under Sec.  
1206.252(b)(2)(i), which we approve, or on a method that we determine 
under Sec.  1206.254. In either case, we will accept or assign a 
royalty value that will approximate the market value of the coal. 
Whether valuing under Sec. Sec.  1206.252(b)(2)(i) or 1206.254, we and 
the lessee will employ a valuation method that uses or approximates 
market value. Current coal valuation regulations also attempt to 
provide royalty values that will approximate the market value of this 
coal. Thus, given the low percentage of non-arm's-length dispositions 
of Federal coal and the use of market-based methods to determine 
royalty value under the current regulations and this rule, if valuation 
does not follow Sec.  1206.252(a) or Sec.  1206.252(b)(1), we estimate 
that the royalty effect of this rule on lessees of Federal coal will be 
nominal.

Cost--Using First Arm's-Length Sale to Value Non-Arm's-Length Sales of 
Indian Coal

    Currently, Indian coal lessees sell their entire production at 
arm's-length, so this rule change will have no cost impact on them.

Cost--Using Sales of Electricity to Value Non-Arm's-Length Sales of 
Indian Coal

    Currently, Indian coal lessees sell their entire production at 
arm's-length, so this rule change will have no cost impact on them.

Cost--Using First Arm's-Length Sale to Value Sales of Indian Coal 
Between Coal Cooperative Members

    Currently, no coal cooperatives are Indian coal lessees, so we do 
not expect there to be any royalty impact as a result of this rule 
change.

Cost--Department Use of Default Provision to Value Federal Oil, Gas, or 
Coal and Indian Coal

    As we discussed above, we added a default provision that addresses 
valuation when the Secretary cannot determine the value of production 
because of a variety of factors, or the Secretary determined that the 
value is wrong for a multitude of reasons (for example, misconduct). In 
those cases, the Secretary will exercise his/her authority and 
considerable discretion, to establish the reasonable value of 
production using a variety of discretionary factors and any other 
information that the Secretary deems appropriate. This default 
provision covers all products (Federal oil, gas, and coal and Indian 
coal) and all pertinent valuation factors (sales, transportation, 
processing, and washing).
    Based on our experience, we anticipate that we will use the default 
provision only in specific cases where conventional valuation 
procedures have not worked to establish a value for royalty purposes. 
As such, we believe that assigning a royalty impact figure to any of 
the default provisions is speculative because (1) each instance will be 
case-specific, (2) we cannot anticipate when we will use the option, 
and (3) we cannot anticipate the value we will require companies to 
pay. Additionally, we estimated that the royalty impact will be 
relatively small because the default provisions will always establish a 
reasonable value of production using market-based transaction data, 
which has always been the basis for our royalty valuation rules in the 
first instance.
B. State and Local Governments
    This rule will not impose any additional burden on local 
governments. We estimate that the States, which this rule impacts, will 
receive an overall increase in royalties as follows:
    States receiving revenues for offshore OCSLA Section 8(g) leases 
will share in a portion of the increased royalties resulting from this 
rule, as will States receiving revenues from onshore Federal lands. 
Based on the ratio of Federal revenues disbursed to States for section 
8(g) leases and onshore States that we detail in the table below, we 
assumed the same proportion of revenue increases for each proposal that 
will impact those State revenues for most of the provisions.

                   Royalty Distributions by Lease Type
------------------------------------------------------------------------
                                               Onshore   Offshore   8(g)
                                                 (%)       (%)      (%)
------------------------------------------------------------------------
Federal.....................................        50        100     73
State.......................................        50          0      0
State (8g)..................................         0          0     27
------------------------------------------------------------------------

    Some provisions, such as deep water gathering allowances, affect 
only Federal revenues, while others, such as the extraordinary 
processing allowance, affect only onshore States and Federal revenues. 
The table summarizing the State and local government royalty increases 
that we provide in section E details these differences.
    The State distribution for offshore royalties will increase at some 
point in time because of the provisions of the Gulf of Mexico Energy 
Security Act of 2006 (GOMESA) (Pub. Law No. 109-432, 120 Stat. 2922). 
Section 105 of GOMESA provides OCS oil and gas revenue sharing 
provisions for the four Gulf producing States (Alabama, Louisiana, 
Mississippi, and Texas) and their eligible coastal political 
subdivisions. Through fiscal year 2016, the only shareable qualified 
revenues originate from leases issued within two small geographic 
areas. Beginning in fiscal year 2017, qualified revenues originating 
from leases issued since the passing of GOMESA located within the 
balance of the GOM acreage will also become shareable. The majority of 
these leases are not yet producing. The time necessary to start 
production operations and to produce royalty-bearing

[[Page 43367]]

quantities varies from lease to lease, and these factors directly 
influence how the distribution of offshore royalties will change over 
time. None of the leases in these frontier areas have begun producing, 
and it is speculative to anticipate when they will begin producing 
royalty-bearing quantities and impact the distribution of revenues to 
States.
C. Indian Lessors
    We estimate that the rule changes to the coal regulations that 
apply to Indian lessors will have no impact on their royalties.
D. Federal Government
    The impact to the Federal government, like the States, will be a 
net overall increase in royalties as a result of these rule changes. In 
fact, the royalty increase that the Federal government anticipates will 
be the difference between the total royalty increase from industry and 
the royalty increase affecting the States. The net yearly impact on the 
Federal government will be approximately 61.8 million that we detail in 
section E.
E. Summary of Royalty Impacts and Costs to Industry, State and Local 
Governments, Indian Lessors, and the Federal Government
    In the table below, the negative values in the Industry column 
represent increases in their estimated royalty burden, while the 
positive values in the other columns represent the increase in each 
affected group's royalty receipts. For the purposes of this summary 
table, we assumed that the average for royalty increases is the 
midpoint of our range.

----------------------------------------------------------------------------------------------------------------
                 Rule provision                      Industry         Federal          State        State 8(g)
----------------------------------------------------------------------------------------------------------------
Gas--replace benchmarks                           ..............  ..............  ..............  ..............
    Affiliate resale............................    ($2,010,000)      $1,390,000        $605,000         $13,500
    Index.......................................    (11,300,000)       7,820,000       3,400,000          75,700
NGLs--replace benchmarks                          ..............  ..............  ..............  ..............
    Affiliate resale............................       (256,000)         191,000          63,000           1,850
    Index.......................................     (1,200,000)         896,000         295,000           8,650
Gas transportation limited to 50%...............     (4,170,000)       2,890,000       1,260,000          27,900
Processing allowance limited to 66\2/3\%........     (5,440,000)       4,060,000       1,340,000          39,200
POP contracts limited to 66\2/3\%...............               0               0               0               0
Extraordinary processing allowance..............    (18,500,000)       9,250,000       9,250,000               0
BBB bond rate change for gas transportation.....     (1,640,000)       1,140,000         494,000          11,000
Eliminate deep water gathering..................    (20,500,000)      20,500,000               0               0
Oil transportation limited to 50%...............     (6,430,000)       5,810,000         594,000          27,100
Oil and gas line losses.........................     (4,571,000)       4,130,000         422,000          19,200
BBB bond rate change for oil transportation.....     (2,380,000)       2,150,000         220,000          10,000
Coal--non-arm's-length netback & co-op sales....               0               0               0               0
                                                 ---------------------------------------------------------------
    Total.......................................    (78,390,000)      60,260,000      17,942,000         234,000
----------------------------------------------------------------------------------------------------------------

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 rule is 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. 
This 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 developed this rule in a manner consistent with 
these requirements.

3. Regulatory Flexibility Act

    The Department certifies that this rule will not have a significant 
economic effect on a substantial number of small entities under the 
Regulatory Flexibility Act (5 U.S.C. 601 et seq.), see item 1 above for 
the analysis.
    This rule will affect lessees under Federal oil and gas leases and 
Federal and Indian coal leases. Federal and Indian mineral lessees are, 
generally, companies classified under the North American Industry 
Classification System (NAICS), as follows:

 Code 211111, which includes companies that extract crude 
petroleum and natural gas
 Code 212111, which includes companies that extract surface 
coal
 Code 212112, which includes companies that extract underground 
coal

    For these NAICS code classifications, a small company is one with 
fewer than 500 employees. Approximately 1,920 different companies 
submit royalty and production reports from Federal oil and gas leases 
and Federal and Indian coal leases to us each month. Of these, 
approximately 65 companies are large businesses under the U.S. Small 
Business Administration definition because they have more than 500 
employees. The Department estimates that the remaining 1,855 companies 
that this rule affects are small businesses.
    As we stated earlier, based on 2010 sales data, this rule will cost 
industry approximately $78 million dollars per year. Small businesses 
accounted for about 20 percent of the royalties paid in 2010. Applying 
that percentage to industry costs, we estimate that the changes in this 
final rule will cost all small-business lessors approximately 
$15,600,000 per year. The amount will vary for each company depending 
on the volume of production that each small business produces and sells 
each year.
    In sum, we do not estimate that this rule will result in a 
significant economic effect on a substantial number of small entities 
because this rule will cost affected small businesses a collective 
total of $15,600,000 per year. Therefore, a Regulatory Flexibility 
Analysis will not be required, and, accordingly, a Small Entity 
Compliance Guide will not be required.
    Your comments are important. The Small Business and Agriculture

[[Page 43368]]

Regulatory Enforcement Ombudsman and ten Regional Fairness Boards 
receive comments from small businesses about Federal agency enforcement 
actions. The Ombudsman annually evaluates the enforcement activities 
and rates each agency's responsiveness to small business. If you wish 
to comment on ONRR's actions, call 1-(888) 734-3247. You may comment to 
the Small Business Administration without fear of retaliation. 
Allegations of discrimination/retaliation filed with the Small Business 
Administration will be investigated for appropriate action.

4. Small Business Regulatory Enforcement Fairness Act

    This rule is not a major rule under 5 U.S.C. 804(2), the Small 
Business Regulatory Enforcement Fairness Act. This rule:
    a. Does not have an annual effect on the economy of $100 million or 
more. We estimate that the maximum effect on all of industry will be 
$84,850,000. The Summary of Royalty Impacts table, as shown in item 1 
above, demonstrates that the economic impact on industry, State and 
local governments and the Federal government will be well below the 
$100 million threshold that the Federal government uses to define a 
rule as having a significant impact on the economy.
    b. Will not cause a major increase in costs or prices for 
consumers; individual industries; Federal, State, or local government 
agencies; or geographic regions. See item 1 above.
    c. Does not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of U. 
S.-based enterprises to compete with foreign-based enterprises. We are 
the only agency that promulgates rules for royalty valuation on Federal 
oil and gas leases and Federal and Indian coal leases.

5. Unfunded Mandates Reform Act

    This rule does not impose an unfunded mandate on State, local, or 
Tribal governments or the private sector of more than $100 million per 
year. This rule does not have a significant or unique effect on State, 
local, or Tribal governments or the private sector. We are not required 
to provide a statement containing the information that the Unfunded 
Mandates Reform Act (2 U.S.C. 1501 et seq.) requires because this rule 
is not an unfunded mandate. See item 1 above.

6. Takings (E.O. 12630)

    Under the criteria in section 2 of E.O. 12630, this rule does not 
have any significant takings implications. This rule will not impose 
conditions or limitations on the use of any private property. This rule 
will apply to Federal oil, Federal gas, Federal coal, and Indian coal 
leases only. Therefore, this rule does not require a Takings 
Implication Assessment.

7. Federalism (E.O. 13132)

    Under the criteria in section 1 of E.O. 13132, this rule does not 
have sufficient Federalism implications to warrant the preparation of a 
Federalism summary impact statement. The management of Federal oil 
leases, Federal gas leases, and Federal and Indian coal leases is the 
responsibility of the Secretary of the Interior, and we distribute all 
of the royalties that we collect from the leases to States, Tribes, and 
individual Indian mineral owners. This rule does not impose 
administrative costs on States or local governments. This rule also 
does not substantially and directly affect the relationship between the 
Federal and State governments. Because this rule does not alter that 
relationship, this rule does not require a Federalism summary impact 
statement.

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

    This rule complies with the requirements of E.O. 12988. 
Specifically, this rule:
    a. Meets the criteria of section 3(a), which requires that we 
review all regulations to eliminate errors and ambiguity and write them 
to minimize litigation.
    b. Meets the criteria of section 3(b)(2), which requires that we 
write all regulations in clear language using clear legal standards.

9. Consultation With Indian Tribal Governments (E.O. 13175)

    Under the criteria in E.O. 13175, we evaluated this final rule and 
determined that it will have potential effects on Federally-recognized 
Indian Tribes. Specifically, this rule will change the valuation method 
for coal produced from Indian leases as discussed above. Accordingly:
    (a) We held a public workshop on October 20, 2011, in Albuquerque, 
New Mexico, to consider Tribal comments on the Indian coal valuation 
regulations.
    (b) We solicited and received comments from a Tribe through our 
Advance Notice of Proposed Rulemaking published on May 27, 2011 (76 FR 
30881).
    (c) We requested further comments from our Tribal partners through 
our bi-annual State and Tribal Royalty Audit Committee meetings held in 
May and November 2015.
    (d) We considered Tribal views in this final rule.

10. Paperwork Reduction Act

    This rule:
    (a) Does not contain any new information collection requirements.
    (b) Does not require a submission to the OMB under the Paperwork 
Reduction Act of 1995 (44 U.S.C. 3501 et seq.).
    This rule also refers to, but does not change, the information 
collection requirements that OMB already approved under OMB Control 
Numbers 1012-0004, 1012-0005, and 1012-0010. Since this rule is 
reorganizing our current regulations, please refer to the Derivations 
Table in Section II for specifics. The corresponding information 
collection burden tables will be updated during their normal renewal 
cycle. See 5 CFR 1320.4(a)(2).

11. National Environmental Policy Act

    This rule does 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 rule qualifies for a 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 
also have determined that this rule is not involved in any of the 
extraordinary circumstances listed in 43 CFR 46.215 that require 
further analysis under NEPA. The procedural changes resulting from 
these amendments will have no consequence on the physical environment. 
This rule does not alter, in any material way, natural resources 
exploration, production, or transportation.

12. Effects on the Nation's Energy Supply (E.O. 13211)

    This rule is not a significant energy action under the definition 
in E.O. 13211; therefore, a Statement of Energy Effects is not 
required.

List of Subjects in 30 CFR Parts 1202 and 1206

    Coal, Continental shelf, Government contracts, Indian lands, 
Mineral royalties, Natural gas, Oil, Oil and gas exploration, Public 
lands--mineral resources, Reporting and recordkeeping requirements.


[[Page 43369]]


    Dated: June 24, 2016.
Kristen J. Sarri,
Principal Deputy Assistant Secretary for Policy, Management and Budget.

Authority and Issuance

    For the reasons discussed in the preamble, ONRR amends 30 CFR parts 
1202 and 1206 as set forth below:

PART 1202--ROYALTIES

0
1. The authority citation for part 1202 continues to read as follows:

    Authority:  5 U.S.C. 301 et seq., 25 U.S.C. 396 et seq., 396a et 
seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et 
seq.,1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.,1331 et 
seq., and 1801 et seq.

Subpart B--Oil, Gas, and OCS Sulfur, General

0
2. In Sec.  1202.51, revise paragraph (b) to read as follows:


Sec.  1202.51  Scope and definitions.

* * * * *
    (b) The definitions in Sec.  1206.20 are applicable to subparts B, 
C, D, and J of this part.

Subpart F--Coal

0
3. Add Sec.  1202.251 to subpart F to read as follows:


Sec.  1202.251  What coal is subject to royalties?

    (a) All coal (except coal unavoidably lost as BLM determines under 
43 CFR part 3400) from a Federal or Indian lease is subject to royalty. 
This includes coal used, sold, or otherwise disposed of by you on or 
off of the lease.
    (b) If you receive compensation for unavoidably lost coal through 
insurance coverage or other arrangements, you must pay royalties at the 
rate specified in the lease on the amount of compensation that you 
receive for the coal. No royalty is due on insurance compensation that 
you received for other losses.
    (c) If you rework waste piles or slurry ponds to recover coal, you 
must pay royalty at the rate specified in the lease at the time when 
you use, sell, or otherwise finally dispose of the recovered coal.
    (1) The applicable royalty rate depends on the production method 
that you used to initially mine the coal contained in the waste pile or 
slurry pond (such as an underground mining method or a surface mining 
method).
    (2) You must allocate coal in waste pits or slurry ponds that you 
initially mined from Federal or Indian leases to those Federal or 
Indian leases regardless of whether it is stored on Federal or Indian 
lands.
    (3) You must maintain accurate records demonstrating how to 
allocate the coal in the waste pit or slurry pond to each individual 
Federal or Indian coal lease.

PART 1206--PRODUCT VALUATION

0
4. The authority citation for part 1206 continues to read as follows:

    Authority: 5 U.S.C. 301 et seq., 25 U.S.C. 396 et seq., 396a et 
seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et 
seq.,1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et 
seq., and 1801 et seq.


0
5. Revise subpart A to read as follows:
Subpart A--General Provisions and Definitions
Sec.
1206.10 Has the Office of Management and Budget (OMB) approved the 
information collection requirements in this part?
1206.20 What definitions apply to this part?

Subpart A--General Provisions and Definitions


Sec.  1206.10  Has the Office of Management and Budget (OMB) approved 
the information collection requirements in this part?

    OMB has approved the information collection requirement contained 
in this part under 44 U.S.C. 3501 et seq. See 30 CFR part 1210 for 
details concerning the estimated reporting burden and how to comment on 
the accuracy of the burden estimate.


Sec.  1206.20  What definitions apply to this part?

    Ad valorem lease means a lease where the royalty due to the lessor 
is based upon a percentage of the amount or value of the coal.
    Affiliate means a person who controls, is controlled by, or is 
under common control with another person. For the purposes of this 
subpart:
    (1) Ownership or common ownership of more than 50 percent of the 
voting securities, or instruments of ownership or other forms of 
ownership, of another person constitutes control. Ownership of less 
than 10 percent constitutes a presumption of non-control 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 each of the 
following factors to determine if there is control under the 
circumstances of a particular case:
    (i) The extent to which there are common officers or directors
    (ii) With respect to the voting securities, or instruments of 
ownership or other forms of ownership: the percentage of ownership or 
common ownership, the relative percentage of ownership or common 
ownership compared to the percentage(s) of ownership by other persons, 
if a person is the greatest single owner, or if there is an opposing 
voting bloc of greater ownership
    (iii) Operation of a lease, plant, pipeline, or other facility
    (iv) The extent of others owners' participation in operations and 
day-to-day management of a lease, plant, or other facility
    (v) Other evidence of power to exercise control over or common 
control with another person
    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    ANS means Alaska North Slope.
    Area means a geographic region at least as large as the limits of 
an oil and/or gas field, in which oil and/or gas lease products have 
similar quality and economic characteristics. Area boundaries are not 
officially designated and the areas are not necessarily named.
    Arm's-length-contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's-
length for any production month, a contract must satisfy this 
definition for that month, as well as when the contract was executed.
    Audit means an examination, conducted under the generally accepted 
Governmental Auditing Standards, of royalty reporting and payment 
compliance activities of lessees, designees or other persons who pay 
royalties, rents, or bonuses on Federal leases or Indian leases.
    BIA means the Bureau of Indian Affairs of the Department of the 
Interior.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    BOEM means the Bureau of Ocean Energy Management of the Department 
of the Interior.
    BSEE means the Bureau of Safety and Environmental Enforcement of 
the Department of the Interior.
    Coal means coal of all ranks from lignite through anthracite.
    Coal cooperative means an entity organized to provide coal or coal-
related services to the entity's members (who may or may not also be 
owners of the entity), partners, and others. The entity may operate as 
a coal lessee, operator,

[[Page 43370]]

payor, logistics provider, or electricity generator, or any of their 
affiliates, and may be organized to be non-profit or for-profit.
    Coal washing means any treatment to remove impurities from coal. 
Coal washing may include, but is not limited to, operations, such as 
flotation, air, water, or heavy media separation; drying; and related 
handling (or combination thereof).
    Compression means the process of raising the pressure of gas.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without processing. Condensate 
is the mixture of liquid hydrocarbons resulting from condensation of 
petroleum hydrocarbons existing initially in a gaseous phase in an 
underground reservoir.
    Constraint means a reduction in, or elimination of, gas flow, 
deliveries, or sales required by the delivery system.
    Contract means any oral or written agreement, including amendments 
or revisions, between two or more persons, that is enforceable by law 
and that, with due consideration, creates an obligation.
    Designee means the person whom the lessee designates to report and 
pay the lessee's royalties for a lease.
    Exchange agreement means an agreement where one person agrees to 
deliver oil to another person at a specified location in exchange for 
oil deliveries at another location. Exchange agreements may or may not 
specify prices for the oil involved. They frequently specify dollar 
amounts reflecting location, quality, or other differentials. Exchange 
agreements include buy/sell agreements, which specify prices to be paid 
at each exchange point and may appear to be two separate sales within 
the same agreement. Examples of other types of exchange agreements 
include, but are not limited to, exchanges of produced oil for specific 
types of crude oil (such as West Texas Intermediate); exchanges of 
produced oil for other crude oil at other locations (Location Trades); 
exchanges of produced oil for other grades of oil (Grade Trades); and 
multi-party exchanges.
    FERC means Federal Energy Regulatory Commission.
    Field means a geographic region situated over one or more 
subsurface oil and gas reservoirs and encompassing at least the 
outermost boundaries of all oil and gas accumulations known within 
those reservoirs, vertically projected to the land surface. State oil 
and gas regulatory agencies usually name onshore fields and designate 
their official boundaries. BOEM names and designates boundaries of OCS 
fields.
    Gas means any fluid, either combustible or non-combustible, 
hydrocarbon or non-hydrocarbon, which is extracted from a reservoir and 
which has neither independent shape nor volume, but tends to expand 
indefinitely. It is a substance that exists in a gaseous or rarefied 
state under standard temperature and pressure conditions.
    Gas plant products means separate marketable elements, compounds, 
or mixtures, whether in liquid, gaseous, or solid form, resulting from 
processing gas, excluding residue gas.
    Gathering means the movement of lease production to a central 
accumulation or treatment point on the lease, unit, or communitized 
area, or to a central accumulation or treatment point off of the lease, 
unit, or communitized area that BLM or BSEE approves for onshore and 
offshore leases, respectively, including any movement of bulk 
production from the wellhead to a platform offshore.
    Geographic region means, for Federal gas, an area at least as large 
as the defined limits of an oil and or gas field in which oil and/or 
gas lease products have similar quality and economic characteristics.
    Gross proceeds means the total monies and other consideration 
accruing for the disposition of any of the following:
    (1) Oil. Gross proceeds also include, but are not limited to, the 
following examples:
    (i) Payments for services such as dehydration, marketing, 
measurement, or gathering which the lessee must perform at no cost to 
the Federal Government
    (ii) The value of services, such as salt water disposal, that the 
producer normally performs but that the buyer performs on the 
producer's behalf
    (iii) Reimbursements for harboring or terminalling fees, royalties, 
and any other reimbursements
    (iv) Tax reimbursements, even though the Federal royalty interest 
may be exempt from taxation
    (v) Payments made to reduce or buy down the purchase price of oil 
produced in later periods by allocating such payments over the 
production whose price that the payment reduces and including the 
allocated amounts as proceeds for the production as it occurs
    (vi) Monies and all other consideration to which a seller is 
contractually or legally entitled but does not seek to collect through 
reasonable efforts
    (2) Gas, residue gas, and gas plant products. Gross proceeds also 
include, but are not limited to, the following examples:
    (i) Payments for services such as dehydration, marketing, 
measurement, or gathering that the lessee must perform at no cost to 
the Federal Government
    (ii) Reimbursements for royalties, fees, and any other 
reimbursements
    (iii) Tax reimbursements, even though the Federal royalty interest 
may be exempt from taxation
    (iv) Monies and all other consideration to which a seller is 
contractually or legally entitled, but does not seek to collect through 
reasonable efforts
    (3) Coal. Gross proceeds also include, but are not limited to, the 
following examples:
    (i) Payments for services such as crushing, sizing, screening, 
storing, mixing, loading, treatment with substances including chemicals 
or oil, and other preparation of the coal that the lessee must perform 
at no cost to the Federal Government or Indian lessor
    (ii) Reimbursements for royalties, fees, and any other 
reimbursements
    (iii) Tax reimbursements even though the Federal or Indian royalty 
interest may be exempt from taxation
    (iv) Monies and all other consideration to which a seller is 
contractually or legally entitled, but does not seek to collect through 
reasonable efforts
    Index means:
    (1) For gas, the calculated composite price ($/MMBtu) of spot 
market sales that a publication that meets ONRR-established criteria 
for acceptability at the index pricing point publishes
    (2) For oil, the calculated composite price ($/barrel) of spot 
market sales that a publication that meets ONRR-established criteria 
for acceptability at the index pricing point publishes.
    Index pricing point means any point on a pipeline for which there 
is an index, which ONRR-approved publications may refer to as a trading 
location.
    Index zone means a field or an area with an active spot market and 
published indices applicable to that field or an area that is 
acceptable to ONRR under Sec.  1206.141(d)(1).
    Indian Tribe means any Indian Tribe, band, nation, pueblo, 
community, rancheria, colony, or other group of Indians for which any 
minerals or interest in minerals is held in trust by the United States 
or is subject to Federal restriction against alienation.
    Individual Indian mineral owner means any Indian for whom minerals 
or

[[Page 43371]]

an interest in minerals is held in trust by the United States or who 
holds title subject to Federal restriction against alienation.
    Keepwhole contract means a processing agreement under which the 
processor delivers to the lessee a quantity of gas after processing 
equivalent to the quantity of gas that the processor received from the 
lessee prior to processing, normally based on heat content, less gas 
used as plant fuel and gas unaccounted for and/or lost. This includes, 
but is not limited to, agreements under which the processor retains all 
NGLs that it recovered from the lessee's gas.
    Lease means any contract, profit-sharing arrangement, joint 
venture, or other agreement issued or approved by the United States 
under any mineral leasing law, including the Indian Mineral Development 
Act, 25 U.S.C. 2101-2108, that authorizes exploration for, extraction 
of, or removal of lease products. Depending on the context, lease may 
also refer to the land area that the authorization covers.
    Lease products mean any leased minerals, attributable to, 
originating from, or allocated to a lease or produced in association 
with a lease.
    Lessee means any person to whom the United States, an Indian Tribe, 
and/or individual Indian mineral owner issues a lease, and any person 
who has been assigned all or a part of record title, operating rights, 
or an obligation to make royalty or other payments required by the 
lease. Lessee includes:
    (1) Any person who has an interest in a lease.
    (2) In the case of leases for Indian coal or Federal coal, an 
operator, payor, or other person with no lease interest who makes 
royalty payments on the lessee's behalf.
    Like quality means similar chemical and physical characteristics.
    Location differential means an amount paid or received (whether in 
money or in barrels of oil) under an exchange agreement that results 
from differences in location between oil delivered in exchange and oil 
received in the exchange. A location differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell exchange agreement.
    Market center means a major point that ONRR recognizes for oil 
sales, refining, or transshipment. Market centers generally are 
locations where ONRR-approved publications publish oil spot prices.
    Marketable condition means lease products which are sufficiently 
free from impurities and otherwise in a condition that they will be 
accepted by a purchaser under a sales contract typical for the field or 
area for Federal oil and gas, and region for Federal and Indian coal.
    Mine means an underground or surface excavation or series of 
excavations and the surface or underground support facilities that 
contribute directly or indirectly to mining, production, preparation, 
and handling of lease products.
    Misconduct means any failure to perform a duty owed to the United 
States under a statute, regulation, or lease, or unlawful or improper 
behavior, regardless of the mental state of the lessee or any 
individual employed by or associated with the lessee.
    Net output means the quantity of:
    (1) For gas, residue gas and each gas plant product that a 
processing plant produces.
    (2) For coal, the quantity of washed coal that a coal wash plant 
produces.
    Netting means reducing the reported sales value to account for an 
allowance instead of reporting the allowance as a separate entry on the 
Report of Sales and Royalty Remittance (Form ONRR-2014) or the Solid 
Minerals Production and Royalty Report (Form ONRR-4430).
    NGLs means Natural Gas Liquids.
    NYMEX price means the average of the New York Mercantile Exchange 
(NYMEX) settlement prices for light sweet crude oil delivered at 
Cushing, Oklahoma, calculated as follows:
    (1) First, sum the prices published for each day during the 
calendar month of production (excluding weekends and holidays) for oil 
to be delivered in the prompt month corresponding to each such day.
    (2) Second, divide the sum by the number of days on which those 
prices are published (excluding weekends and holidays).
    Oil means a mixture of hydrocarbons that existed in the liquid 
phase in natural underground reservoirs, remains liquid at atmospheric 
pressure after passing through surface separating facilities, and is 
marketed or used as a liquid. Condensate recovered in lease separators 
or field facilities is oil.
    ONRR means the Office of Natural Resources Revenue of the 
Department of the Interior.
    ONRR-approved commercial price bulletin means a publication that 
ONRR approves for determining NGLs prices.
    ONRR-approved publication means:
    (1) For oil, a publication that ONRR approves for determining ANS 
spot prices or WTI differentials.
    (2) For gas, a publication that ONRR approves for determining index 
pricing points.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters, as 
defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301), and 
of which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Payor means any person who reports and pays royalties under a 
lease, regardless of whether that person also is a lessee.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Processing means any process designed to remove elements or 
compounds (hydrocarbon and non-hydrocarbon) from gas, including 
absorption, adsorption, or refrigeration. Field processes which 
normally take place on or near the lease, such as natural pressure 
reduction, mechanical separation, heating, cooling, dehydration, and 
compression, are not considered processing. The changing of pressures 
and/or temperatures in a reservoir is not considered processing. The 
use of a Joule-Thomson (JT) unit to remove NGLs from gas is considered 
processing regardless of where the JT unit is located, provided that 
you market the NGLs as NGLs.
    Processing allowance means a deduction in determining royalty value 
for the reasonable, actual costs the lessee incurs for processing gas.
    Prompt month means the nearest month of delivery for which NYMEX 
futures prices are published during the trading month.
    Quality differential means an amount paid or received under an 
exchange agreement (whether in money or in barrels of oil) that results 
from differences in API gravity, sulfur content, viscosity, metals 
content, and other quality factors between oil delivered and oil 
received in the exchange. A quality differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell agreement.
    Region for coal means the eight Federal coal production regions, 
which the Bureau of Land Management designates as follows: Denver-Raton 
Mesa Region, Fort Union Region, Green River-Hams Fork Region, Powder 
River Region, San Juan River Region, Southern Appalachian Region, 
Uinta-Southwestern Utah Region, and Western Interior Region. See 44 FR 
65197 (1979).
    Residue gas means that hydrocarbon gas consisting principally of 
methane resulting from processing gas.

[[Page 43372]]

    Rocky Mountain Region means the States of Colorado, Montana, North 
Dakota, South Dakota, Utah, and Wyoming, except for those portions of 
the San Juan Basin and other oil-producing fields in the ``Four 
Corners'' area that lie within Colorado and Utah.
    Roll means an adjustment to the NYMEX price that is calculated as 
follows: Roll = .6667 x (P0-P1) + .3333 x 
(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. December was the prompt month (for year 2011) from October 21 
through November 18. January was the first month following the month of 
production, and February was the second month following the month of 
production. P0, therefore, is the average of the daily NYMEX 
settlement prices for deliveries during December published for each 
business day between October 21 and November 18. P1 is the 
average of the daily NYMEX settlement prices for deliveries during 
January published for each business day between October 21 and November 
18. P2 is the average of the daily NYMEX settlement prices 
for deliveries during February published for each business day between 
October 21 and November 18. In this example, assume that P0 
= $95.08 per bbl, P1 = $95.03 per bbl, and P2 = 
$94.93 per bbl. In this example (a declining market), Roll = .6667 x 
($95.08-$95.03) + .3333 x ($95.08-$94.93) = $0.03 + $0.05 = $0.08. You 
add this number to the NYMEX price.
    (2) Example 2. Prices in Out Months are Higher Going Forward: The 
month of production for which you must determine royalty value is 
November. November was the prompt month (for year 2012) from September 
21 through October 22. December was the first month following the month 
of production, and January was the second month following the month of 
production. P0, therefore, is the average of the daily NYMEX 
settlement prices for deliveries during November published for each 
business day between September 21 and October 22. P1 is the 
average of the daily NYMEX settlement prices for deliveries during 
December published for each business day between September 21 and 
October 22. P2 is the average of the daily NYMEX settlement 
prices for deliveries during January published for each business day 
between September 21 and October 22. In this example, assume that 
P0 = $91.28 per bbl, P1 = $91.65 per bbl, and 
P2 = $92.10 per bbl. In this example (a rising market), Roll 
= .6667 x ($91.28-$91.65) + .3333 x ($91.28-$92.10) = (-$0.25) + (-
$0.27) = (-$0.52). You add this negative number to the NYMEX price 
(effectively, a subtraction from the NYMEX price).
    Sale means a contract between two persons where:
    (1) The seller unconditionally transfers title to the oil, gas, gas 
plant product, or coal to the buyer and does not retain any related 
rights, such as the right to buy back similar quantities of oil, gas, 
gas plant product, or coal from the buyer elsewhere;
    (2) The buyer pays money or other consideration for the oil, gas, 
gas plant product, or coal; and
    (3) The parties' intent is for a sale of the oil, gas, gas plant 
product, or coal to occur.
    Section 6 lease means an OCS lease subject to section 6 of the 
Outer Continental Shelf Lands Act, as amended, 43 U.S.C. 1335.
    Short ton means 2,000 pounds.
    Spot price means the price under a spot sales contract where:
    (1) A seller agrees to sell to a buyer a specified amount of oil at 
a specified price over a specified period of short duration.
    (2) No cancellation notice is required to terminate the sales 
agreement.
    (3) There is no obligation or implied intent to continue to sell in 
subsequent periods.
    Tonnage means tons of coal measured in short tons.
    Trading month means the period extending from the second business 
day before the 25th day of the second calendar month preceding the 
delivery month (or, if the 25th day of that month is a non-business 
day, the second business day before the last business day preceding the 
25th day of that month) through the third business day before the 25th 
day of the calendar month preceding the delivery month (or, if the 25th 
day of that month is a non-business day, the third business day before 
the last business day preceding the 25th day of that month), unless the 
NYMEX publishes a different definition or different dates on its 
official Web site, www.cmegroup.com, in which case, the NYMEX 
definition will apply.
    Transportation allowance means a deduction in determining royalty 
value for the reasonable, actual costs that the lessee incurs for 
moving:
    (1) Oil to a point of sale or delivery off of the lease, unit area, 
or communitized area. The transportation allowance does not include 
gathering costs.
    (2) Unprocessed gas, residue gas, or gas plant products to a point 
of sale or delivery off of the lease, unit area, or communitized area, 
or away from a processing plant. The transportation allowance does not 
include gathering costs.
    (3) Coal to a point of sale remote from both the lease and mine or 
wash plant.
    Washing allowance means a deduction in determining royalty value 
for the reasonable, actual costs the lessee incurs for coal washing.
    WTI differential means the average of the daily mean differentials 
for location and quality between a grade of crude oil at a market 
center and West Texas Intermediate (WTI) crude oil at Cushing published 
for each day for which price publications perform surveys for 
deliveries during the production month, calculated over the number of 
days on which those differentials are published (excluding weekends and 
holidays). Calculate the daily mean differentials by averaging the 
daily high and low differentials for the month in the selected 
publication. Use only the days and corresponding differentials for 
which such differentials are published.

0
6. Revise subpart C to read as follows:
Subpart C--Federal Oil
Sec.
1206.100 What is the purpose of this subpart?
1206.101 How do I calculate royalty value for oil I or my affiliate 
sell(s) under an arm's-length contract?
1206.102 How do I value oil not sold under an arm's-length contract?
1206.103 What publications does ONRR approve?
1206.104 How will ONRR determine if my royalty payments are correct?
1206.105 How will ONRR determine the value of my oil for royalty 
purposes?

[[Page 43373]]

1206.106 What records must I keep to support my calculations of 
value under this subpart?
1206.107 What are my responsibilities to place production into 
marketable condition and to market production?
1206.108 How do I request a valuation determination?
1206.109 Does ONRR protect information I provide?
1206.110 What general transportation allowance requirements apply to 
me?
1206.111 How do I determine a transportation allowance if I have an 
arm's-length transportation contract?
1206.112 How do I determine a transportation allowance if I do not 
have an arm's-length transportation contract?
1206.113 What adjustments and transportation allowances apply when I 
value oil production from my lease using NYMEX prices or ANS spot 
prices?
1206.114 How will ONRR identify market centers?
1206.115 What are my reporting requirements under an arm's-length 
transportation contract?
1206.116 What are my reporting requirements under a non-arm's-length 
transportation contract?
1206.117 What interest and penalties apply if I improperly report a 
transportation allowance?
1206.118 What reporting adjustments must I make for transportation 
allowances?
1206.119 How do I determine royalty quantity and quality?

Subpart C--Federal Oil


Sec.  1206.100  What is the purpose of this subpart?

    (a) This subpart applies to all oil produced from Federal oil and 
gas leases onshore and on the OCS. It explains how you, as a lessee, 
must calculate the value of production for royalty purposes consistent 
with mineral leasing laws, other applicable laws, and lease terms.
    (b) If you are a designee and if you dispose of production on 
behalf of a lessee, the terms ``you'' and ``your'' in this subpart 
refer to you and not to the lessee. In this circumstance, you must 
determine and report royalty value for the lessee's oil by applying the 
rules in this subpart to your disposition of the lessee's oil.
    (c) If you are a designee and only report for a lessee and do not 
dispose of the lessee's production, references to ``you'' and ``your'' 
in this subpart refer to the lessee and not the designee. In this 
circumstance, you as a designee must determine and report royalty value 
for the lessee's oil by applying the rules in this subpart to the 
lessee's disposition of its oil.
    (d) If the regulations in this subpart are inconsistent with a(an): 
Federal statute; settlement agreement between the United States and a 
lessee resulting from administrative or judicial litigation; written 
agreement between the lessee and ONRR's Director establishing a method 
to determine the value of production from any lease that ONRR expects 
would at least approximate the value established under this subpart; 
express provision of an oil and gas lease subject to this subpart, then 
the statute, settlement agreement, written agreement, or lease 
provision will govern to the extent of the inconsistency.
    (e) ONRR may audit, monitor, or review and adjust all royalty 
payments.


Sec.  1206.101  How do I calculate royalty value for oil I or my 
affiliate sell(s) under an arm's-length contract?

    (a) The value of oil under this section for royalty purposes is the 
gross proceeds accruing to you or your affiliate under the arm's-length 
contract less applicable allowances determined under Sec.  1206.111 or 
Sec.  1206.112. This value does not apply if you exercise an option to 
use a different value provided in paragraph (c)(1) or (c)(2)(i) of this 
section or if ONRR decides to value your oil under Sec.  1206.105. You 
must use this paragraph (a) to value oil when:
    (1) You sell under an arm's-length sales contract; or
    (2) You sell or transfer to your affiliate or another person under 
a non-arm's-length contract and that affiliate or person, or another 
affiliate of either of them, then sells the oil under an arm's-length 
contract, unless you exercise the option provided in paragraph 
(c)(2)(i) of this section.
    (b) If you have multiple arm's-length contracts to sell oil 
produced from a lease that is valued under paragraph (a) of this 
section, the value of the oil is the volume-weighted average of the 
values established under this section for each contract for the sale of 
oil produced from that lease.
    (c)(1) If you enter into an arm's-length exchange agreement, or 
multiple sequential arm's-length exchange agreements, and following the 
exchange(s) that you or your affiliate sell(s) the oil received in the 
exchange(s) under an arm's-length contract, then you may use either 
paragraph (a) of this section or Sec.  1206.102 to value your 
production for royalty purposes. If you fail to make the election 
required under this paragraph, you may not make a retroactive election, 
and ONRR may decide your value under Sec.  1206.105.
    (i) If you use paragraph (a) of this section, your gross proceeds 
are the gross proceeds under your or your affiliate's arm's-length 
sales contract after the exchange(s) occur(s). You must adjust your 
gross proceeds for any location or quality differential, or other 
adjustments, that you received or paid under the arm's-length exchange 
agreement(s). If ONRR determines that any arm's-length exchange 
agreement does not reflect reasonable location or quality 
differentials, ONRR may decide your value under Sec.  1206.105. You may 
not otherwise use the price or differential specified in an arm's-
length exchange agreement to value your production.
    (ii) When you elect under Sec.  1206.101(c)(1) to use paragraph (a) 
of this section or Sec.  1206.102, you must make the same election for 
all of your production from the same unit, communitization agreement, 
or lease (if the lease is not part of a unit or communitization 
agreement) sold under arm's-length contracts following arm's-length 
exchange agreements. You may not change your election more often than 
once every two years.
    (2)(i) If you sell or transfer your oil production to your 
affiliate, and that affiliate or another affiliate then sells the oil 
under an arm's-length contract, you may use either paragraph (a) of 
this section or Sec.  1206.102 to value your production for royalty 
purposes.
    (ii) When you elect under paragraph (c)(2)(i) of this section to 
use paragraph (a) of this section or Sec.  1206.102, you must make the 
same election for all of your production from the same unit, 
communitization agreement, or lease (if the lease is not part of a unit 
or communitization agreement) that your affiliates resell at arm's-
length. You may not change your election more often than once every two 
years.


Sec.  1206.102  How do I value oil not sold under an arm's-length 
contract?

    This section explains how to value oil that you may not value under 
Sec.  1206.101 or that you elect under Sec.  1206.101(c)(1) to value 
under this section, unless ONRR decides to value your oil under 
1206.105. First, determine if paragraph (a), (b), or (c) of this 
section applies to production from your lease, or if you may apply 
paragraph (d) or (e) with ONRR's approval.
    (a) Production from leases in California or Alaska. Value is the 
average of the daily mean ANS spot prices published in any ONRR-
approved publication during the trading month most concurrent with the 
production month. For example, if the production month is June, 
calculate the average of the daily mean prices using the daily ANS spot 
prices published in the ONRR-approved publication for all of the 
business days in June.

[[Page 43374]]

    (1) To calculate the daily mean spot price, you must average the 
daily high and low prices for the month in the selected publication.
    (2) You must use only the days and corresponding spot prices for 
which such prices are published.
    (3) You must adjust the value for applicable location and quality 
differentials, and you may adjust it for transportation costs, under 
Sec.  1206.111.
    (4) After you select an ONRR-approved publication, you may not 
select a different publication more often than once every two years, 
unless the publication you use is no longer published or ONRR revokes 
its approval of the publication. If you must change publications, you 
must begin a new two-year period.
    (b) Production from leases in the Rocky Mountain Region. This 
paragraph provides methods and options for valuing your production 
under different factual situations. You must consistently apply 
paragraph (b)(2) or (3) of this section to value all of your production 
from the same unit, communitization agreement, or lease (if the lease 
or a portion of the lease is not part of a unit or communitization 
agreement) that you cannot value under Sec.  1206.101 or that you elect 
under Sec.  1206.101(c)(1) to value under this section.
    (1)You may elect to value your oil under either paragraph (b)(2) or 
(3) of this section. After you select either paragraph (b)(2) or (3) of 
this section, you may not change to the other method more often than 
once every two years, unless the method you have been using is no 
longer applicable and you must apply the other paragraph. If you change 
methods, you must begin a new two-year period.
    (2) Value is the volume-weighted average of the gross proceeds 
accruing to the seller under your or your affiliate's arm's-length 
contracts for the purchase or sale of production from the field or area 
during the production month.
    (i) The total volume purchased or sold under those contracts must 
exceed 50 percent of your and your affiliate's production from both 
Federal and non-Federal leases in the same field or area during that 
month.
    (ii) Before calculating the volume-weighted average, you must 
normalize the quality of the oil in your or your affiliate's arm's-
length purchases or sales to the same gravity as that of the oil 
produced from the lease.
    (3) Value is the NYMEX price (without the roll), adjusted for 
applicable location and quality differentials and transportation costs 
under Sec.  1206.113.
    (4) If you demonstrate to ONRR's satisfaction that paragraphs 
(b)(2) through (3) of this section result in an unreasonable value for 
your production as a result of circumstances regarding that production, 
ONRR's Director may establish an alternative valuation method.
    (c) Production from leases not located in California, Alaska, or 
the Rocky Mountain Region. (1) Value is the NYMEX price, plus the roll, 
adjusted for applicable location and quality differentials and 
transportation costs under Sec.  1206.113.
    (2) If ONRR's Director determines that the use of the roll no 
longer reflects prevailing industry practice in crude oil sales 
contracts or that the most common formula that industry uses to 
calculate the roll changes, ONRR may terminate or modify the use of the 
roll under paragraph (c)(1) of this section at the end of each two-year 
period as of January 1, 2017, through a notice published in the Federal 
Register not later than 60 days before the end of the two-year period. 
ONRR will explain the rationale for terminating or modifying the use of 
the roll in this notice.
    (d) Unreasonable value. If ONRR determines that the NYMEX price or 
ANS spot price does not represent a reasonable royalty value in any 
particular case, ONRR may decide to value your oil under Sec.  
1206.105.
    (e) Production delivered to your refinery and the NYMEX price or 
ANS spot price is an unreasonable value. If ONRR determines that the 
NYMEX price or ANS spot price does not represent a reasonable royalty 
value in any particular case, ONRR may decide to value your oil under 
Sec.  1206.105.


Sec.  1206.103  What publications does ONRR approve?

    (a) ONRR will periodically publish on www.onrr.gov a list of ONRR-
approved publications for the NYMEX price and ANS spot price based on 
certain criteria including, but not limited to:
    (1) Publications buyers and sellers frequently use.
    (2) Publications frequently mentioned in purchase or sales 
contracts.
    (3) Publications that use adequate survey techniques, including 
development of estimates based on daily surveys of buyers and sellers 
of crude oil, and, for ANS spot prices, buyers and sellers of ANS crude 
oil.
    (4) Publications independent from ONRR, other lessors, and lessees.
    (b) Any publication may petition ONRR to be added to the list of 
acceptable publications.
    (c) ONRR will specify the tables that you must use in the 
acceptable publications.
    (d) ONRR may revoke its approval of a particular publication if we 
determine that the prices or differentials published in the publication 
do not accurately represent NYMEX prices or differentials or ANS spot 
market prices or differentials.


Sec.  1206.104  How will ONRR determine if my royalty payments are 
correct?

    (a)(1) ONRR may monitor, review, and audit the royalties that you 
report, and, if ONRR determines that your reported value is 
inconsistent with the requirements of this subpart, ONRR may direct you 
to use a different measure of royalty value or decide your value under 
Sec.  1206.105.
    (2) If ONRR directs you to use a different royalty value, you must 
either pay any additional royalties due, plus late payment interest 
calculated under Sec. Sec.  1218.54 and 1218.102 of this chapter), or 
report a credit for--or request a refund of--any overpaid royalties.
    (b) When the provisions in this subpart refer to gross proceeds, in 
conducting reviews and audits, ONRR will examine if your or your 
affiliate's contract reflects the total consideration actually 
transferred, either directly or indirectly, from the buyer to you or to 
your affiliate for the oil. If ONRR determines that a contract does not 
reflect the total consideration, ONRR may decide your value under Sec.  
1206.105.
    (c) ONRR may decide your value under Sec.  1206.105 if ONRR 
determines that the gross proceeds accruing to you or your affiliate 
under a contract do not reflect reasonable consideration because:
    (1) There is misconduct by or between the contracting parties;
    (2) You have breached your duty to market the oil for the mutual 
benefit of yourself and the lessor by selling your oil at a value that 
is unreasonably low. ONRR may consider a sales price to be unreasonably 
low if it is 10 percent less than the lowest reasonable measures of 
market price including--but not limited to--index prices and prices 
reported to ONRR for like quality oil; or
    (3) ONRR cannot determine if you properly valued your oil under 
Sec.  1206.101 or Sec.  1206.102 for any reason including--but not 
limited to--your or your affiliate's failure to provide documents that 
ONRR requests under 30 CFR part 1212, subpart B.
    (d) You have the burden of demonstrating that your or your 
affiliate's contract is arm's-length.

[[Page 43375]]

    (e) ONRR may require you to certify that the provisions in your or 
your affiliate's contract include all of the consideration that the 
buyer paid to you or your affiliate, either directly or indirectly, for 
the oil.
    (f)(1) Absent contract revision or amendment, if you or your 
affiliate fail(s) to take proper or timely action to receive prices or 
benefits to which you or your affiliate are entitled, you must pay 
royalty based upon that obtainable price or benefit.
    (2) If you or your affiliate apply in a timely manner 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 in a timely manner, for a quantity of oil.
    (g)(1) You or your affiliate must make all contracts, contract 
revisions, or amendments in writing, and all parties to the contract 
must sign the contract, contract revisions, or amendments.
    (2) If you or your affiliate fail(s) to comply with paragraph 
(g)(1) of this section, ONRR may determine your value under Sec.  
1206.105.
    (3) This provision applies notwithstanding any other provisions in 
this title 30 to the contrary.


Sec.  1206.105  How will ONRR determine the value of my oil for royalty 
purposes?

    If ONRR decides that we will value your oil for royalty purposes 
under Sec.  1206.104, or any other provision in this subpart, then we 
will determine value, for royalty purposes, by considering any 
information that we deem relevant, which may include, but is not 
limited to, the following:
    (a) The value of like-quality oil in the same field or nearby 
fields or areas
    (b) The value of like-quality oil from the refinery or area
    (c) Public sources of price or market information that ONRR deems 
reliable
    (d) Information available and reported to ONRR, including but not 
limited to on Form ONRR-2014 and the Oil and Gas Operations Report 
(Form ONRR-4054)
    (e) Costs of transportation or processing if ONRR determines that 
they are applicable
    (f) Any information that ONRR deems relevant regarding the 
particular lease operation or the salability of the oil


Sec.  1206.106  What records must I keep to support my calculations of 
value under this subpart?

    If you determine the value of your oil under this subpart, you must 
retain all data relevant to the determination of royalty value.
    (a) You must show both of the following:
    (1) How you calculated the value that you reported, including all 
adjustments for location, quality, and transportation.
    (2) How you complied with these rules.
    (b) You can find recordkeeping requirements in parts 1207 and 1212 
of this chapter.
    (c) ONRR may review and audit your data, and ONRR will direct you 
to use a different value if we determine that the reported value is 
inconsistent with the requirements of this subpart.


Sec.  1206.107  What are my responsibilities to place production into 
marketable condition and to market production?

    (a) You must place oil in marketable condition and market the oil 
for the mutual benefit of the lessee and the lessor at no cost to the 
Federal government.
    (b) If you use gross proceeds under an arm's-length contract in 
determining value, you must increase those gross proceeds to the extent 
that the purchaser, or any other person, provides certain services that 
the seller normally would be responsible to perform to place the oil in 
marketable condition or to market the oil.


Sec.  1206.108  How do I request a valuation determination?

    (a) You may request a valuation determination from ONRR regarding 
any oil produced. Your request must:
    (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);
    (6) Suggest your proposed valuation method.
    (b) In response to your request, ONRR may:
    (1) Request that the Assistant Secretary for Policy, Management and 
Budget issue a valuation determination;
    (2) Decide that ONRR will issue guidance; or
    (3) Inform you in writing that ONRR will not provide a 
determination or guidance. Situations in which ONRR typically will not 
provide any determination or guidance include, but are not limited to, 
the following:
    (i) Requests for guidance on hypothetical situations
    (ii) Matters that are the subject of pending litigation or 
administrative appeals
    (c)(1) A valuation determination that the Assistant Secretary for 
Policy, Management and Budget signs is binding on both you and ONRR 
until the Assistant Secretary modifies or rescinds it.
    (2) After the Assistant Secretary issues a valuation 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 
Sec. Sec.  1218.54 and 1218.102 of this chapter.
    (3) A valuation determination that 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 that ONRR issues is not binding on ONRR, delegated 
States, or you with respect to the specific situation addressed in the 
guidance.
    (1) Guidance and ONRR's decision whether or not to issue guidance 
or request an Assistant Secretary determination, or neither, under 
paragraph (b) of this section, are not appealable decisions or orders 
under 30 CFR part 1290.
    (2) If you receive an order requiring you to pay royalty on the 
same basis as the guidance, you may appeal that order under 30 CFR part 
1290.
    (e) ONRR or the Assistant Secretary may use any of the applicable 
valuation criteria in this subpart to provide guidance or to 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 valuation determination issued under 
paragraph (d) of this section, unless:
    (1) There was a misstatement or omission of material facts; or
    (2) The facts subsequently developed are materially different from 
the facts on which the guidance was based.

[[Page 43376]]

    (h) ONRR may make requests and replies under this section available 
to the public, subject to the confidentiality requirements under Sec.  
1206.109.


Sec.  1206.109  Does ONRR protect information that I provide?

    (a) Certain information that you or your affiliate submit(s) to 
ONRR regarding valuation of oil, including transportation allowances, 
may be exempt from disclosure.
    (b) To the extent that applicable laws and regulations permit, ONRR 
will keep confidential any data that 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.


Sec.  1206.110  What general transportation allowance requirements 
apply to me?

    (a) ONRR will allow a deduction for the reasonable, actual costs to 
transport oil from the lease to the point off of the lease under Sec.  
1206.110, Sec.  1206.111, or Sec.  1206.112, as applicable. You may not 
deduct transportation costs that you incur to move a particular volume 
of production to reduce royalties that you owe on production for which 
you did not incur those costs. This paragraph applies when:
    (1)(i) The movement to the sales point is not gathering.
    (ii) For oil produced on the OCS, the movement of oil from the 
wellhead to the first platform is not transportation; and
    (2) You value oil under Sec.  1206.101 based on a sale at a point 
off of the lease, unit, or communitized area where the oil is produced; 
or
    (3) You do not value your oil under Sec.  1206.102(a)(3) or (b)(3).
    (b) You must calculate the deduction for transportation costs based 
on your or your affiliate's cost of transporting each product through 
each individual transportation system. If your or your affiliate's 
transportation contract includes more than one liquid product, you must 
allocate costs consistently and equitably to each of the liquid 
products that are transported. Your allocation must use the same 
proportion as the ratio of the volume of each liquid product (excluding 
waste products with no value) to the volume of all liquid products 
(excluding waste products with no value).
    (1) You may not take an allowance for transporting lease production 
that is not royalty-bearing.
    (2) You may propose to ONRR a prospective cost allocation method 
based on the values of the liquid products transported. ONRR will 
approve the method if it is consistent with the purposes of the 
regulations in this subpart.
    (3) You may use your proposed procedure to calculate a 
transportation allowance beginning with the production month following 
the month when ONRR received your proposed procedure until ONRR accepts 
or rejects your cost allocation. If ONRR rejects your cost allocation, 
you must amend your Form ONRR-2014 for the months that you used the 
rejected method and pay any additional royalty due, plus late payment 
interest.
    (c)(1) Where you or your affiliate transport(s) both gaseous and 
liquid products through the same transportation system, you must 
propose a cost allocation procedure to ONRR.
    (2) You may use your proposed procedure to calculate a 
transportation allowance until ONRR accepts or rejects your cost 
allocation. If ONRR rejects your cost allocation, you must amend your 
Form ONRR-2014 for the months when you used the rejected method and pay 
any additional royalty and interest due.
    (3) You must submit your initial proposal, including all available 
data, within three months after you first claim the allocated 
deductions on Form ONRR-2014.
    (d)(1) Your transportation allowance may not exceed 50 percent of 
the value of the oil, as determined under Sec.  1206.101.
    (2) If ONRR approved your request to take a transportation 
allowance in excess of the 50-percent limitation under former Sec.  
1206.109(c), that approval is terminated as January 1, 2017.
    (e) You must express transportation allowances for oil as a dollar-
value equivalent. If your or your affiliate's payments for 
transportation under a contract are not on a dollar-per-unit basis, you 
must convert whatever consideration you or your affiliate are paid to a 
dollar-value equivalent.
    (f) ONRR may determine your transportation allowance under Sec.  
1206.105 because:
    (1) There is misconduct by or between the contracting parties;
    (2) ONRR determines that the consideration that you or your 
affiliate paid under an arm's-length transportation contract does not 
reflect the reasonable cost of the transportation because you breached 
your duty to market the oil for the mutual benefit of yourself and the 
lessor by transporting your oil at a cost that is unreasonably high. We 
may consider a transportation allowance to be unreasonably high if it 
is 10 percent higher than the highest reasonable measures of 
transportation costs including, but not limited to, transportation 
allowances reported to ONRR and tariffs for gas, residue gas, or gas 
plant product transported through the same system; or
    (3) ONRR cannot determine if you properly calculated a 
transportation allowance under Sec.  1206.111 or Sec.  1206.112 for any 
reason, including, but not limited to, your or your affiliate's failure 
to provide documents that ONRR requests under 30 CFR part 1212, subpart 
B.
    (g) You do not need ONRR's approval before reporting a 
transportation allowance.


Sec.  1206.111  How do I determine a transportation allowance if I have 
an arm's-length transportation contract?

    (a)(1) If you or your affiliate incur transportation costs under an 
arm's-length transportation contract, you may claim a transportation 
allowance for the reasonable, actual costs incurred, as more fully 
explained in paragraph (b) of this section, except as provided in Sec.  
1206.110(f) and subject to the limitation in Sec.  1206.110(d).
    (2) You must be able to demonstrate that your or your affiliate's 
contract is at arm's-length.
    (3) You do not need ONRR's approval before reporting a 
transportation allowance for costs incurred under an arm's-length 
transportation contract.
    (b) Subject to the requirements of paragraph (c) of this section, 
you may include, but are not limited to, the following costs to 
determine your transportation allowance under paragraph (a) of this 
section; you may not use any cost as a deduction that duplicates all or 
part of any other cost that you use under this section including, but 
not limited to:
    (1) The amount that you pay under your arm's-length transportation 
contract or tariff.
    (2) Fees paid (either in volume or in value) for actual or 
theoretical line losses.
    (3) Fees paid for administration of a quality bank.
    (4) Fees paid to a terminal operator for loading and unloading of 
crude oil into or from a vessel, vehicle, pipeline, or other 
conveyance.
    (5) Fees paid for short-term storage (30 days or less) incidental 
to transportation as a transporter requires.
    (6) Fees paid to pump oil to another carrier's system or vehicles 
as required under a tariff.
    (7) Transfer fees paid to a hub operator associated with physical

[[Page 43377]]

movement of crude oil through the hub when you do not sell the oil at 
the hub. These fees do not include title transfer fees.
    (8) Payments for a volumetric deduction to cover shrinkage when 
high-gravity petroleum (generally in excess of 51 degrees API) is mixed 
with lower gravity crude oil for transportation.
    (9) Costs of securing a letter of credit, or other surety, that the 
pipeline requires you, as a shipper, to maintain.
    (10) Hurricane surcharges that you or your affiliate actually 
pay(s).
    (11) The cost of carrying on your books as inventory a volume of 
oil that the pipeline operator requires you, as a shipper, to maintain 
and that you do maintain in the line as line fill. You must calculate 
this cost as follows:
    (i) First, multiply the volume that the pipeline requires you to 
maintain--and that you do maintain--in the pipeline by the value of 
that volume for the current month calculated under Sec.  1206.101 or 
Sec.  1206.102, as applicable.
    (ii) Second, multiply the value calculated under paragraph 
(b)(11)(i) of this section by the monthly rate of return, calculated by 
dividing the rate of return specified in Sec.  1206.112(i)(3) by 12.
    (c) You may not include the following costs to determine your 
transportation allowance under paragraph (a) of this section:
    (1) Fees paid for long-term storage (more than 30 days)
    (2) Administrative, handling, and accounting fees associated with 
terminalling
    (3) Title and terminal transfer fees
    (4) Fees paid to track and match receipts and deliveries at a 
market center or to avoid paying title transfer fees
    (5) Fees paid to brokers
    (6) Fees paid to a scheduling service provider
    (7) Internal costs, including salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to 
schedule, nominate, and account for sale or movement of production
    (8) Gauging fees
    (d) If you have no written contract for the arm's-length 
transportation of oil, then ONRR will determine your transportation 
allowance under Sec.  1206.105. You may not use this paragraph (d) if 
you or your affiliate perform(s) your own transportation.
    (1) You must propose to ONRR a method to determine the allowance 
using the procedures in Sec.  1206.108(a).
    (2) You may use that method to determine your allowance until ONRR 
issues its determination.


Sec.  1206.112  How do I determine a transportation allowance if I do 
not have an arm's-length transportation contract?

    (a) This section applies if you or your affiliate do(es) not have 
an arm's-length transportation contract, including situations where you 
or your affiliate provide your own transportation services. You must 
calculate your transportation allowance based on your or your 
affiliate's reasonable, actual costs for transportation during the 
reporting period using the procedures prescribed in this section.
    (b) Your or your affiliate's actual costs may include the 
following:
    (1) Capital costs and operating and maintenance expenses under 
paragraphs (e), (f), and (g) of this section.
    (2) Overhead under paragraph (h) of this section.
    (3)(i) Depreciation and a return on undepreciated capital 
investment under paragraph (i)(1) of this section, or you may elect to 
use a cost equal to a return on the initial depreciable capital 
investment in the transportation system under paragraph (i)(2) of this 
section. After you have elected to use either method for a 
transportation system, you may not later elect to change to the other 
alternative without ONRR's approval. If ONRR accepts your request to 
change methods, you may use your changed method beginning with the 
production month following the month when ONRR received your change 
request.
    (ii) A return on the reasonable salvage value under paragraph 
(i)(1)(iii) of this section after you have depreciated the 
transportation system to its reasonable salvage value.
    (c) To the extent not included in costs identified in paragraphs 
(e) through (h) of this section.
    (1) If you or your affiliate incur(s) the following actual costs 
under your or your affiliate's non-arm's-length contract, you may 
include these costs in your calculations under this section:
    (i) Fees paid to a non-affiliated terminal operator for loading and 
unloading of crude oil into or from a vessel, vehicle, pipeline, or 
other conveyance
    (ii) Transfer fees paid to a hub operator associated with physical 
movement of crude oil through the hub when you do not sell the oil at 
the hub; these fees do not include title transfer fees
    (iii) A volumetric deduction to cover shrinkage when high-gravity 
petroleum (generally in excess of 51 degrees API) is mixed with lower 
gravity crude oil for transportation
    (iv) Fees paid to a non-affiliated quality bank administrator for 
administration of a quality bank
    (v) The cost of carrying on your books as inventory a volume of oil 
that the pipeline operator requires you, as a shipper, to maintain--and 
that you do maintain--in the line as line fill; you must calculate this 
cost as follows:
    (A) First, multiply the volume that the pipeline requires you to 
maintain--and that you do maintain--in the pipeline by the value of 
that volume for the current month calculated under Sec.  1206.101 or 
Sec.  1206.102, as applicable.
    (B) Second, multiply the value calculated under paragraph 
(c)(1)(v)(A) of this section by the monthly rate of return, calculated 
by dividing the rate of return specified in Sec.  1206.112(i)(3) by 12.
    (2) You may not include in your transportation allowance:
    (i) Any of the costs identified under Sec.  1206.111(c); and/or
    (ii) Fees paid (either in volume or in value) for actual or 
theoretical line losses.
    (d) You may not use any cost as a deduction that duplicates all or 
part of any other cost that you use under this section.
    (e) Allowable capital investment costs are generally those for 
depreciable fixed assets (including the costs of delivery and 
installation of capital equipment) that are an integral part of the 
transportation system.
    (f) Allowable operating expenses include the following:
    (1) Operations supervision and engineering.
    (2) Operations labor.
    (3) Fuel.
    (4) Utilities.
    (5) Materials.
    (6) Ad valorem property taxes.
    (7) Rent.
    (8) Supplies.
    (9) Any other directly allocable and attributable operating expense 
that you can document.
    (g) Allowable maintenance expenses include the following
    (1) Maintenance of the transportation system.
    (2) Maintenance of equipment.
    (3) Maintenance labor.
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (h) Overhead, directly attributable and allocable to the operation 
and maintenance of the transportation system, is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (i)(1) To calculate depreciation and a return on undepreciated 
capital

[[Page 43378]]

investment, you may elect to use either a straight-line depreciation 
method (based on the life of equipment or on the life of the reserves 
that the transportation system services), or you may elect to use a 
unit-of-production method. After you make an election, you may not 
change methods without ONRR's approval. If ONRR accepts your request to 
change methods, you may use your changed method beginning with the 
production month following the month when ONRR received your change 
request.
    (i) A change in ownership of a transportation system will not alter 
the depreciation schedule that the original transporter/lessee 
established for purposes of the allowance calculation.
    (ii) You may depreciate a transportation system, with or without a 
change in ownership, only once.
    (iii)(A) To calculate the return on undepreciated capital 
investment, you may use an amount equal to the undepreciated capital 
investment in the transportation system multiplied by the rate of 
return that you determine under paragraph (i)(3) of this section.
    (B) After you have depreciated a transportation system to the 
reasonable salvage value, you may continue to include in the allowance 
calculation a cost equal to the reasonable salvage value multiplied by 
a rate of return under paragraph (i)(3) of this section.
    (2) As an alternative to using depreciation and a return on 
undepreciated capital investment, as provided under paragraph (b)(3) of 
this section, you may use as a cost an amount equal to the allowable 
initial capital investment in the transportation system multiplied by 
the rate of return determined under paragraph (i)(3) of this section. 
You may not include depreciation in your allowance.
    (3) The rate of return is the industrial rate associated with 
Standard & Poor's BBB rating.
    (i) You must use the monthly average BBB rate that Standard & 
Poor's publishes for the first month for which the allowance is 
applicable.
    (ii) You must re-determine the rate at the beginning of each 
subsequent calendar year.


Sec.  1206.113  What adjustments and transportation allowances apply 
when I value oil production from my lease using NYMEX prices or ANS 
spot prices?

    This section applies when you use NYMEX prices or ANS spot prices 
to calculate the value of production under Sec.  1206.102. As specified 
in this section, you must adjust the NYMEX price to reflect the 
difference in value between your lease and Cushing, Oklahoma, or adjust 
the ANS spot price to reflect the difference in value between your 
lease and the appropriate ONRR-recognized market center at which the 
ANS spot price is published (for example, Long Beach, California, or 
San Francisco, California). Paragraph (a) of this section explains how 
you adjust the value between the lease and the market center, and 
paragraph (b) of this section explains how you adjust the value between 
the market center and Cushing when you use NYMEX prices. Paragraph (c) 
of this section explains how adjustments may be made for quality 
differentials that are not accounted for through exchange agreements. 
Paragraph (d) of this section gives some examples. References in this 
section to ``you'' include your affiliates, as applicable.
    (a) To adjust the value between the lease and the market center:
    (1)(i) For oil that you exchange at arm's-length between your lease 
and the market center (or between any intermediate points between those 
locations), you must calculate a lease-to-market center differential by 
the applicable location and quality differentials derived from your 
arm's-length exchange agreement applicable to production during the 
production month.
    (ii) For oil that you exchange between your lease and the market 
center (or between any intermediate points between those locations) 
under an exchange agreement that is not at arm's-length, you must 
obtain approval from ONRR for a location and quality differential. 
Until you obtain such approval, you may use the location and quality 
differential derived from that exchange agreement applicable to 
production during the production month. If ONRR prescribes a different 
differential, you must apply ONRR's differential to all periods for 
which you used your proposed differential. You must pay any additional 
royalties due resulting from using ONRR's differential, plus late 
payment interest from the original royalty due date, or you may report 
a credit for any overpaid royalties, plus interest, under 30 U.S.C. 
1721(h).
    (2) For oil that you transport between your lease and the market 
center (or between any intermediate points between those locations), 
you may take an allowance for the cost of transporting that oil between 
the relevant points, as determined under Sec.  1206.111 or Sec.  
1206.112, as applicable.
    (3) If you transport or exchange at arm's-length (or both transport 
and exchange) at least 20 percent--but not all--of your oil produced 
from the lease to a market center, you must determine the adjustment 
between the lease and the market center for the oil that is not 
transported or exchanged (or both transported and exchanged) to or 
through a market center as follows:
    (i) Determine the volume-weighted average of the lease-to-market 
center adjustment calculated under paragraphs (a)(1) and (2) of this 
section for the oil that you do transport or exchange (or both 
transport and exchange) from your lease to a market center.
    (ii) Use that volume-weighted average lease-to-market center 
adjustment as the adjustment for the oil that you do not transport or 
exchange (or both transport and exchange) from your lease to a market 
center.
    (4) If you transport or exchange (or both transport and exchange) 
less than 20 percent of the crude oil produced from your lease between 
the lease and a market center, you must propose to ONRR an adjustment 
between the lease and the market center for the portion of the oil that 
you do not transport or exchange (or both transport and exchange) to a 
market center. Until you obtain such approval, you may use your 
proposed adjustment. If ONRR prescribes a different adjustment, you 
must apply ONRR's adjustment to all periods for which you used your 
proposed adjustment. You must pay any additional royalties due 
resulting from using ONRR's adjustment, plus late payment interest from 
the original royalty due date, or you may report a credit for any 
overpaid royalties plus interest under 30 U.S.C. 1721(h).
    (5) You may not both take a transportation allowance and use a 
location and quality adjustment or exchange differential for the same 
oil between the same points.
    (b) For oil that you value using NYMEX prices, you must adjust the 
value between the market center and Cushing, Oklahoma, as follows:
    (1) If you have arm's-length exchange agreements between the market 
center and Cushing under which you exchange to Cushing at least 20 
percent of all of the oil that you own at the market center during the 
production month, you must use the volume-weighted average of the 
location and quality differentials from those agreements as the 
adjustment between the market center and Cushing for all of the oil 
that you produce from the leases during that production month for which 
that market center is used.
    (2) If paragraph (b)(1) of this section does not apply, you must 
use the WTI differential published in an ONRR-approved publication for 
the market center nearest to your lease, for crude oil most similar in 
quality to your

[[Page 43379]]

production, as the adjustment between the market center and Cushing. 
For example, for light sweet crude oil produced offshore of Louisiana, 
you must use the WTI differential for Light Louisiana Sweet crude oil 
at St. James, Louisiana. After you select an ONRR-approved publication, 
you may not select a different publication more often than once every 
two years, unless the publication you use is no longer published or 
ONRR revokes its approval of the publication. If you must change 
publications, you must begin a new two-year period.
    (3) If neither paragraph (b)(1) nor (2) of this section applies, 
you may propose an alternative differential to ONRR. Until you obtain 
such approval, you may use your proposed differential. If ONRR 
prescribes a different differential, you must apply ONRR's differential 
to all periods for which you used your proposed differential. You must 
pay any additional royalties due resulting from using ONRR's 
differential, plus late payment interest from the original royalty due 
date, or you may report a credit for any overpaid royalties plus 
interest under 30 U.S.C. 1721(h).
    (c)(1) If you adjust for location and quality differentials or for 
transportation costs under paragraphs (a) and (b) of this section, you 
also must adjust the NYMEX price or ANS spot price for quality based on 
premiums or penalties determined by pipeline quality bank 
specifications at intermediate commingling points or at the market 
center if those points are downstream of the royalty measurement point 
that BSEE or BLM, as applicable, approve. You must make this adjustment 
only if, and to the extent that, such adjustments were not already 
included in the location and quality differentials determined from your 
arm's-length exchange agreements.
    (2) If the quality of your oil, as adjusted, is still different 
from the quality of the representative crude oil at the market center 
after making the quality adjustments described in paragraphs (a), (b), 
and (c)(1) of this section, you may make further gravity adjustments 
using posted price gravity tables. If quality bank adjustments do not 
incorporate or provide for adjustments for sulfur content, you may make 
sulfur adjustments, based on the quality of the representative crude 
oil at the market center, of 5.0 cents per one-tenth percent difference 
in sulfur content.
    (i) You may request prior ONRR approval to use a different 
adjustment.
    (ii) If ONRR approves your request to use a different quality 
adjustment, you may begin using that adjustment for the production 
month following the month when ONRR received your request.
    (d) The examples in this paragraph illustrate how to apply the 
requirement of this section.
    (1) Example. Assume that a Federal lessee produces crude oil from a 
lease near Artesia, New Mexico. Further, assume that the lessee 
transports the oil to Roswell, New Mexico, and then exchanges the oil 
to Midland, Texas. Assume that the lessee refines the oil received in 
exchange at Midland. Assume that the NYMEX price is $86.21/bbl, 
adjusted for the roll; that the WTI differential (Cushing to Midland) 
is -$2.27/bbl; that the lessee's exchange agreement between Roswell and 
Midland results in a location and quality differential of -$0.08/bbl; 
and that the lessee's actual cost of transporting the oil from Artesia 
to Roswell is $0.40/bbl. In this example, the royalty value of the oil 
is $86.21-$2.27-$0.08-$0.40 = $83.46/bbl.
    (2) Example. Assume the same facts as in the example in paragraph 
(d)(1) of this section, except that the lessee transports and exchanges 
to Midland 40 percent of the production from the lease near Artesia and 
transports the remaining 60 percent directly to its own refinery in 
Ohio. In this example, the 40 percent of the production would be valued 
at $83.46/bbl, as explained in the previous example. In this example, 
the other 60 percent also would be valued at $83.46/bbl.
    (3) Example. Assume that a Federal lessee produces crude oil from a 
lease near Bakersfield, California. Further, assume that the lessee 
transports the oil to Hynes Station and then exchanges the oil to 
Cushing, which it further exchanges with oil that it refines. Assume 
that the ANS spot price is $105.65/bbl and that the lessee's actual 
cost of transporting the oil from Bakersfield to Hynes Station is 
$0.28/bbl. The lessee must request approval from ONRR for a location 
and quality adjustment between Hynes Station and Long Beach. For 
example, the lessee likely would propose using the tariff on Line 63 
from Hynes Station to Long Beach as the adjustment between those 
points. Assume that adjustment to be $0.72, including the sulfur and 
gravity bank adjustments, and that ONRR approves the lessee's request. 
In this example, the preliminary (because the location and quality 
adjustment is subject to ONRR's review) royalty value of the oil is 
$105.65-$0.72-$0.28 = $104.65/bbl. The fact that oil was exchanged to 
Cushing does not change the use of ANS spot prices for royalty 
valuation.


Sec.  1206.114  How will ONRR identify market centers?

    ONRR will monitor market activity and, if necessary, add to or 
modify the list of market centers that we publish to www.onrr.gov. ONRR 
will consider the following factors and conditions in specifying market 
centers:
    (a) Points where ONRR-approved publications publish prices useful 
for index purposes.
    (b) Markets served.
    (c) Input from industry and others knowledgeable in crude oil 
marketing and transportation.
    (d) Simplification.
    (e) Other relevant matters.


Sec.  1206.115  What are my reporting requirements under an arm's-
length transportation contract?

    (a) You must use a separate entry on Form ONRR-2014 to notify ONRR 
of an allowance based on transportation costs that you or your 
affiliate incur(s).
    (b) ONRR may require you or your affiliate to submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents.
    (c) You can find recordkeeping requirements in parts 1207 and 1212 
of this chapter.


Sec.  1206.116  What are my reporting requirements under a non-arm's-
length transportation contract?

    (a) You must use a separate entry on Form ONRR-2014 to notify ONRR 
of an allowance based on transportation costs that you or your 
affiliate incur(s).
    (b)(1) For new non-arm's-length transportation facilities or 
arrangements, you must base your initial deduction on estimates of 
allowable transportation costs for the applicable period.
    (2) You must use your or your affiliate's most recently available 
operations data for the transportation system as your estimate, if 
available. If such data is not available, you must use estimates based 
on data for similar transportation systems.
    (3) Section 1206.118 applies when you amend your report based on 
the actual costs.
    (c) ONRR may require you or your affiliate to submit all data used 
to calculate the allowance deduction. You may find recordkeeping 
requirements in parts 1207 and 1212 of this chapter.
    (d) If you are authorized under Sec.  1206.112(j) to use an 
exception to the requirement to calculate your actual transportation 
costs, you must follow the reporting requirements of Sec.  1206.115.

[[Page 43380]]

Sec.  1206.117  What interest and penalties apply if I improperly 
report a transportation allowance?

    (a) If you deduct a transportation allowance on Form ONRR-2014 that 
exceeds 50 percent of the value of the oil transported, you must pay 
additional royalties due, plus late payment interest calculated under 
Sec. Sec.  1218.54 and 1218.102 of this chapter, on the excess 
allowance amount taken from the date when that amount is taken to the 
date when you pay the additional royalties due.
    (b) If you improperly net a transportation allowance against the 
oil instead of reporting the allowance as a separate entry on Form 
ONRR-2014, ONRR may assess a civil penalty under 30 CFR part 1241.


Sec.  1206.118  What reporting adjustments must I make for 
transportation allowances?

    (a) If your actual transportation allowance is less than the amount 
that 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 Sec. Sec.  1218.54 and 1218.102 of 
this chapter from the date when you took the deduction to the date when 
you repay the difference.
    (b) If the actual transportation allowance is greater than the 
amount that you claimed on Form ONRR-2014 for any month during the 
period reported on the allowance form, you are entitled to a credit 
plus interest.


Sec.  1206.119  How do I determine royalty quantity and quality?

    (a) You must calculate royalties based on the quantity and quality 
of oil as measured at the point of royalty settlement that BLM or BSEE 
approves for onshore leases and OCS leases, respectively.
    (b) If you base the value of oil determined under this subpart on a 
quantity and/or quality that is different from the quantity and/or 
quality at the point of royalty settlement that BLM or BSEE approves, 
you must adjust that value for the differences in quantity and/or 
quality.
    (c) You may not make any deductions from the royalty volume or 
royalty value for actual or theoretical losses. Any actual loss that 
you sustain before the royalty settlement metering or measurement point 
is not subject to royalty if BLM or BSEE, whichever is appropriate, 
determines that such loss was unavoidable.
    (d) You must pay royalties on 100 percent of the volume measured at 
the approved point of royalty settlement. You may not claim a reduction 
in that measured volume for actual losses beyond the approved point of 
royalty settlement or for theoretical losses that you claim to have 
taken place either before or after the approved point of royalty 
settlement.
0
7. Revise subpart D to read as follows:
Subpart D--Federal Gas
Sec.
1206.140 What is the purpose and scope of this subpart?
1206.141 How do I calculate royalty value for unprocessed gas that I 
or my affiliate sell(s) under an arm's-length or non-arm's-length 
contract?
1206.142 How do I calculate royalty value for processed gas that I 
or my affiliate sell(s) under an arm's-length or non-arm's-length 
contract?
1206.143 How will ONRR determine if my royalty payments are correct?
1206.144 How will ONRR determine the value of my gas for royalty 
purposes?
1206.145 What records must I keep in order to support my 
calculations of royalty under this subpart?
1206.146 What are my responsibilities to place production into 
marketable condition and to market production?
1206.147 When is an ONRR audit, review, reconciliation, monitoring, 
or other like process considered final?
1206.148 How do I request a valuation determination?
1206.149 Does ONRR protect information that I provide?
1206.150 How do I determine royalty quantity and quality?
1206.151 [Reserved]
1206.152 What general transportation allowance requirements apply to 
me?
1206.153 How do I determine a transportation allowance if I have an 
arm's-length transportation contract?
1206.154 How do I determine a transportation allowance if I have a 
non-arm's-length transportation contract?
1206.155 What are my reporting requirements under an arm's-length 
transportation contract?
1206.156 What are my reporting requirements under a non-arm's-length 
transportation contract?
1206.157 What interest and penalties apply if I improperly report a 
transportation allowance?
1206.158 What reporting adjustments must I make for transportation 
allowances?
1206.159 What general processing allowances requirements apply to 
me?
1206.160 How do I determine a processing allowance if I have an 
arm's-length processing contract?
1206.161 How do I determine a processing allowance if I have a non-
arm's-length processing contract?
1206.162 What are my reporting requirements under an arm's-length 
processing contract?
1206.163 What are my reporting requirements under a non-arm's-length 
processing contract?
1206.164 What interest and penalties apply if I improperly report a 
processing allowance?
1206.165 What reporting adjustments must I make for processing 
allowances?

Subpart D--Federal Gas


Sec.  1206.140  What is the purpose and scope of this subpart?

    (a) This subpart applies to all gas produced from Federal oil and 
gas leases onshore and on the Outer Continental Shelf (OCS). It 
explains how you, as a lessee, must calculate the value of production 
for royalty purposes consistent with mineral leasing laws, other 
applicable laws, and lease terms.
    (b) The terms ``you'' and ``your'' in this subpart refer to the 
lessee.
    (c) If the regulations in this subpart are inconsistent with a(an): 
Federal statute; settlement agreement between the United States and a 
lessee resulting from administrative or judicial litigation; written 
agreement between the lessee and ONRR's Director establishing a method 
to determine the value of production from any lease that ONRR expects 
would at least approximate the value established under this subpart; 
express provision of an oil and gas lease subject to this subpart, then 
the statute, settlement agreement, written agreement, or lease 
provision will govern to the extent of the inconsistency.
    (d) ONRR may audit and order you to adjust all royalty payments.


Sec.  1206.141  How do I calculate royalty value for unprocessed gas 
that I or my affiliate sell(s) under an arm's-length or non-arm's-
length contract?

    (a) This section applies to unprocessed gas. Unprocessed gas is:
    (1) Gas that is not processed;
    (2) Any gas that you are not required to value under Sec.  1206.142 
or that ONRR does not value under Sec.  1206.144; or
    (3) Any gas that you sell prior to processing based on a price per 
MMBtu or Mcf when the price is not based on the residue gas and gas 
plant products.
    (b) The value of gas under this section for royalty purposes is the 
gross proceeds accruing to you or your affiliate under the first arm's-
length contract less a transportation allowance determined under Sec.  
1206.152. This value does not apply if you exercise the option in 
paragraph (c) of this section or if ONRR decides to value your gas 
under Sec.  1206.144. You must use this paragraph (b) to value gas 
when:
    (1) You sell under an arm's-length contract;
    (2) You sell or transfer unprocessed gas to your affiliate or 
another person under a non-arm's-length contract and

[[Page 43381]]

that affiliate or person, or an affiliate of either of them, then sells 
the gas under an arm's-length contract, unless you exercise the option 
provided in paragraph (c) of this section;
    (3) You, your affiliate, or another person sell(s) unprocessed gas 
produced from a lease under multiple arm's-length contracts, and that 
gas is valued under this paragraph. Unless you exercise the option 
provided in paragraph (c) of this section, the value of the gas is the 
volume-weighted average of the values, established under this 
paragraph, for each contract for the sale of gas produced from that 
lease; or
    (4) You or your affiliate sell(s) under a pipeline cash-out 
program. In that case, for over-delivered volumes within the tolerance 
under a pipeline cash-out program, the value is the price that the 
pipeline must pay you or your affiliate under the transportation 
contract. You must use the same value for volumes that exceed the over-
delivery tolerances, even if those volumes are subject to a lower price 
under the transportation contract.
    (c) If you do not sell under an arm's-length contract, you may 
elect to value your gas under this paragraph (c). You may not change 
your election more often than once every two years.
    (1)(i) If you can only transport gas to one index pricing point 
published in an ONRR-approved publication, available at www.onrr.gov, 
your value, for royalty purposes, is the highest reported monthly 
bidweek price for that index pricing point for the production month.
    (ii) If you can transport gas to more than one index pricing point 
published in an ONRR-approved publication available at www.onrr.gov, 
your value, for royalty purposes, is the highest reported monthly 
bidweek price for the index pricing points to which your gas could be 
transported for the production month, whether or not there are 
constraints for that production month.
    (iii) If there are sequential index pricing points on a pipeline, 
you must use the first index pricing point at or after your gas enters 
the pipeline.
    (iv) You must reduce the number calculated under paragraphs 
(c)(1)(i) and (ii) of this section by 5 percent for sales from the OCS 
Gulf of Mexico and by 10 percent for sales from all other areas, but 
not by less than 10 cents per MMBtu or more than 30 cents per MMBtu.
    (v) After you select an ONRR-approved publication available at 
www.onrr.gov, you may not select a different publication more often 
than once every two years.
    (vi) ONRR may exclude an individual index pricing point found in an 
ONRR-approved publication if ONRR determines that the index pricing 
point does not accurately reflect the values of production. ONRR will 
publish a list of excluded index pricing points available at 
www.onrr.gov.
    (2) You may not take any other deductions from the value calculated 
under this paragraph (c).
    (d) If some of your gas is used, lost, unaccounted for, or retained 
as a fee under the terms of a sales or service agreement, that gas will 
be valued for royalty purposes using the same royalty valuation method 
for valuing the rest of the gas that you do sell.
    (e) If you have no written contract for the sale of gas or no sale 
of gas subject to this section and:
    (1) There is an index pricing point for the gas, then you must 
value your gas under paragraph (c) of this section; or
    (2) There is not an index pricing point for the gas, then ONRR will 
decide the value under Sec.  1206.144.
    (i) You must propose to ONRR a method to determine the value using 
the procedures in Sec.  1206.148(a).
    (ii) You may use that method to determine value, for royalty 
purposes, until ONRR issues our decision.
    (iii) After ONRR issues our determination, you must make the 
adjustments under Sec.  1206.143(a)(2).


Sec.  1206.142  How do I calculate royalty value for processed gas that 
I or my affiliate sell(s) under an arm's-length or non-arm's-length 
contract?

    (a) This section applies to the valuation of processed gas, 
including but not limited to:
    (1) Gas that you or your affiliate do not sell, or otherwise 
dispose of, under an arm's-length contract prior to processing.
    (2) Gas where your or your affiliate's arm's-length contract for 
the sale of gas prior to processing provides for payment to be 
determined on the basis of the value of any products resulting from 
processing, including residue gas or natural gas liquids.
    (3) Gas that you or your affiliate process under an arm's-length 
keepwhole contract.
    (4) Gas where your or your affiliate's arm's-length contract 
includes a reservation of the right to process the gas, and you or your 
affiliate exercise(s) that right.
    (b) The value of gas subject to this section, for royalty purposes, 
is the combined value of the residue gas and all gas plant products 
that you determine under this section plus the value of any condensate 
recovered downstream of the point of royalty settlement without 
resorting to processing that you determine under subpart C of this part 
less applicable transportation and processing allowances that you 
determine under this subpart, unless you exercise the option provided 
in paragraph (d) of this section.
    (c) The value of residue gas or any gas plant product under this 
section for royalty purposes is the gross proceeds accruing to you or 
your affiliate under the first arm's-length contract. This value does 
not apply if you exercise the option provided in paragraph (d) of this 
section, or if ONRR decides to value your residue gas or any gas plant 
product under Sec.  1206.144. You must use this paragraph (c) to value 
residue gas or any gas plant product when:
    (1) You sell under an arm's-length contract;
    (2) You sell or transfer to your affiliate or another person under 
a non-arm's-length contract, and that affiliate or person, or another 
affiliate of either of them, then sells the residue gas or any gas 
plant product under an arm's-length contract, unless you exercise the 
option provided in paragraph (d) of this section;
    (3) You, your affiliate, or another person sell(s), under multiple 
arm's-length contracts, residue gas or any gas plant products recovered 
from gas produced from a lease that you value under this paragraph. In 
that case, unless you exercise the option provided in paragraph (d) of 
this section, because you sold non-arm's-length to your affiliate or 
another person, the value of the residue gas or any gas plant product 
is the volume-weighted average of the gross proceeds established under 
this paragraph for each arm's-length contract for the sale of residue 
gas or any gas plant products recovered from gas produced from that 
lease; or
    (4) You or your affiliate sell(s) under a pipeline cash-out 
program. In that case, for over-delivered volumes within the tolerance 
under a pipeline cash-out program, the value is the price that the 
pipeline must pay to you or your affiliate under the transportation 
contract. You must use the same value for volumes that exceed the over-
delivery tolerances, even if those volumes are subject to a lower price 
under the transportation contract.
    (d) If you do not sell under an arm's-length contract, you may 
elect to value your residue gas and NGLs under this paragraph (d). You 
may not change your election more often than once every two years.
    (1)(i) If you can only transport residue gas to one index pricing 
point published in an ONRR-approved publication available at 
www.onrr.gov, your value,

[[Page 43382]]

for royalty purposes, is the highest reported monthly bidweek price for 
that index pricing point for the production month.
    (ii) If you can transport residue gas to more than one index 
pricing point published in an ONRR-approved publication available at 
www.onrr.gov, your value, for royalty purposes, is the highest reported 
monthly bidweek price for the index pricing points to which your gas 
could be transported for the production month, whether or not there are 
constraints, for the production month.
    (iii) If there are sequential index pricing points on a pipeline, 
you must use the first index pricing point at or after your residue gas 
enters the pipeline.
    (iv) You must reduce the number calculated under paragraphs 
(d)(1)(i) and (ii) of this section by 5 percent for sales from the OCS 
Gulf of Mexico and by 10 percent for sales from all other areas, but 
not by less than 10 cents per MMBtu or more than 30 cents per MMBtu.
    (v) After you select an ONRR-approved publication available at 
www.onrr.gov, you may not select a different publication more often 
than once every two years.
    (vi) ONRR may exclude an individual index pricing point found in an 
ONRR-approved publication if ONRR determines that the index pricing 
point does not accurately reflect the values of production. ONRR will 
publish a list of excluded index pricing points on www.onrr.gov.
    (2)(i) If you sell NGLs in an area with one or more ONRR-approved 
commercial price bulletins available at www.onrr.gov, you must choose 
one bulletin, and your value, for royalty purposes, is the monthly 
average price for that bulletin for the production month.
    (ii) You must reduce the number calculated under paragraph 
(d)(2)(i) of this section by the amounts that ONRR posts at 
www.onrr.gov for the geographic location of your lease. The methodology 
that ONRR will use to calculate the amounts is set forth in the 
preamble to this regulation. This methodology is binding on you and 
ONRR. ONRR will update the amounts periodically using this methodology.
    (iii) After you select an ONRR-approved commercial price bulletin 
available at www.onrr.gov, you may not select a different commercial 
price bulletin more often than once every two years.
    (3) You may not take any other deductions from the value calculated 
under this paragraph (d).
    (4) ONRR will post changes to any of the rates in this paragraph 
(d) on its Web site.
    (e) If some of your gas or gas plant products are used, lost, 
unaccounted for, or retained as a fee under the terms of a sales or 
service agreement, that gas will be valued for royalty purposes using 
the same royalty valuation method for valuing the rest of the gas or 
gas plant products that you do sell.
    (f) If you have no written contract for the sale of gas or no sale 
of gas subject to this section and:
    (1) There is an index pricing point or commercial price bulletin 
for the gas, then you must value your gas under paragraph (d) of this 
section.
    (2) There is not an index pricing point or commercial price 
bulletin for the gas, then ONRR will determine the value under Sec.  
1206.144.
    (i) You must propose to ONRR a method to determine the value using 
the procedures in Sec.  1206.148(a).
    (ii) You may use that method to determine value, for royalty 
purposes, until ONRR issues our decision.
    (iii) After ONRR issues our determination, you must make the 
adjustments under Sec.  1206.143(a)(2).


Sec.  1206.143  How will ONRR determine if my royalty payments are 
correct?

    (a)(1) ONRR may monitor, review, and audit the royalties that you 
report. If ONRR determines that your reported value is inconsistent 
with the requirements of this subpart, ONRR will direct you to use a 
different measure of royalty value or decide your value under Sec.  
1206.144.
    (2) If ONRR directs you to use a different royalty value, you must 
either pay any additional royalties due, plus late payment interest 
calculated under Sec. Sec.  1218.54 and 1218.102 of this chapter, or 
report a credit for, or request a refund of, any overpaid royalties.
    (b) When the provisions in this subpart refer to gross proceeds, in 
conducting reviews and audits, ONRR will examine if your or your 
affiliate's contract reflects the total consideration actually 
transferred, either directly or indirectly, from the buyer to you or 
your affiliate for the gas, residue gas, or gas plant products. If ONRR 
determines that a contract does not reflect the total consideration, 
ONRR may decide your value under Sec.  1206.144.
    (c) ONRR may decide your value under Sec.  1206.144 if ONRR 
determines that the gross proceeds accruing to you or your affiliate 
under a contract do not reflect reasonable consideration because:
    (1) There is misconduct by or between the contracting parties;
    (2) You have breached your duty to market the gas, residue gas, or 
gas plant products for the mutual benefit of yourself and the lessor by 
selling your gas, residue gas, or gas plant products at a value that is 
unreasonably low. ONRR may consider a sales price unreasonably low if 
it is 10 percent less than the lowest reasonable measures of market 
price, including, but not limited to, index prices and prices reported 
to ONRR for like-quality gas, residue gas, or gas plant products; or
    (3) ONRR cannot determine if you properly valued your gas, residue 
gas, or gas plant products under Sec.  1206.141 or Sec.  1206.142 for 
any reason, including, but not limited to, your or your affiliate's 
failure to provide documents that ONRR requests under 30 CFR part 1212, 
subpart B.
    (d) You have the burden of demonstrating that your or your 
affiliate's contract is arm's-length.
    (e) ONRR may require you to certify that the provisions in your or 
your affiliate's contract include(s) all of the consideration that the 
buyer paid to you or your affiliate, either directly or indirectly, for 
the gas, residue gas, or gas plant products.
    (f)(1) Absent contract revision or amendment, if you or your 
affiliate fail(s) to take proper or timely action to receive prices or 
benefits to which you or your affiliate are entitled, you must pay 
royalty based upon that obtainable price or benefit.
    (2) If you or your affiliate make timely application for a price 
increase or benefit allowed under your or your affiliate's contract, 
but the purchaser refuses, and you or your affiliate take reasonable, 
documented measures to force purchaser compliance, you will not owe 
additional royalties unless or until you or your affiliate receive 
additional monies or consideration resulting from the price increase. 
You may not construe this paragraph to permit you to avoid your royalty 
payment obligation in situations where a purchaser fails to pay, in 
whole or in part, or in a timely manner, for a quantity of gas, residue 
gas, or gas plant products.
    (g)(1) You or your affiliate must make all contracts, contract 
revisions, or amendments in writing, and all parties to the contract 
must sign the contract, contract revisions, or amendments.
    (2) If you or your affiliate fail(s) to comply with paragraph 
(g)(1) of this section, ONRR may decide your value under Sec.  
1206.144.
    (3) This provision applies notwithstanding any other provisions in 
this title 30 to the contrary.

[[Page 43383]]

Sec.  1206.144  How will ONRR determine the value of my gas for royalty 
purposes?

    If ONRR decides to value your gas, residue gas, or gas plant 
products for royalty purposes under Sec.  1206.143, or any other 
provision in this subpart, then ONRR will determine the value, for 
royalty purposes, by considering any information that we deem relevant, 
which may include, but is not limited to:
    (a) The value of like-quality gas in the same field or nearby 
fields or areas.
    (b) The value of like-quality residue gas or gas plant products 
from the same plant or area.
    (c) Public sources of price or market information that ONRR deems 
to be reliable.
    (d) Information available or reported to ONRR, including, but not 
limited to, on Form ONRR-2014 and Form ONRR-4054.
    (e) Costs of transportation or processing if ONRR determines that 
they are applicable.
    (f) Any information that ONRR deems relevant regarding the 
particular lease operation or the salability of the gas.


Sec.  1206.145  What records must I keep in order to support my 
calculations of royalty under this subpart?

    If you value your gas under this subpart, you must retain all data 
relevant to the determination of the royalty that you paid. You can 
find recordkeeping requirements in parts 1207 and 1212 of this chapter.
    (a) You must show:
    (1) How you calculated the royalty value, including all allowable 
deductions; and
    (2) How you complied with this subpart.
    (b) Upon request, you must submit all data to ONRR. You must comply 
with any such requirement within the time that ONRR specifies.


Sec.  1206.146  What are my responsibilities to place production into 
marketable condition and to market production?

    (a) You must place gas, residue gas, and gas plant products in 
marketable condition and market the gas, residue gas, and gas plant 
products for the mutual benefit of the lessee and the lessor at no cost 
to the Federal government.
    (b) If you use gross proceeds under an arm's-length contract to 
determine royalty, you must increase those gross proceeds to the extent 
that the purchaser, or any other person, provides certain services that 
you normally are responsible to perform in order to place the gas, 
residue gas, and gas plant products in marketable condition or to 
market the gas.


Sec.  1206.147  When is an ONRR audit, review, reconciliation, 
monitoring, or other like process considered final?

    Notwithstanding any provision in these regulations to the contrary, 
ONRR does not consider any audit, review, reconciliation, monitoring, 
or other like process that results in ONRR re-determining royalty due, 
under this subpart, final or binding as against the Federal government 
or its beneficiaries unless ONRR chooses to, in writing, formally close 
the audit period.


Sec.  1206.148  How do I request a valuation determination?

    (a) You may request a valuation determination from ONRR regarding 
any gas produced. Your request must:
    (1) Be in writing;
    (2) Identify specifically all leases involved, all interest owners 
of those leases, the designee(s), and the operator(s) for those leases;
    (3) Completely explain all relevant facts. You must inform ONRR of 
any changes to relevant facts that occur before we respond to your 
request;
    (4) Include copies of all relevant documents;
    (5) Provide your analysis of the issue(s), including citations to 
all relevant precedents (including adverse precedents); and
    (6) Suggest your proposed valuation method.
    (b) In response to your request, ONRR may:
    (1) Request that the Assistant Secretary for Policy, Management and 
Budget issue a determination;
    (2) Decide that ONRR will issue guidance; or
    (3) Inform you in writing that ONRR will not provide a 
determination or guidance. Situations in which ONRR typically will not 
provide any determination or guidance include, but are not limited to:
    (i) Requests for guidance on hypothetical situations; or
    (ii) Matters that are the subject of pending litigation or 
administrative appeals.
    (c)(1) A determination that the Assistant Secretary for Policy, 
Management and Budget signs is binding on both you and ONRR until the 
Assistant Secretary modifies or rescinds it.
    (2) After the Assistant Secretary issues a determination, you must 
make any adjustments to royalty payments that follow from the 
determination, and, if you owe additional royalties, you must pay the 
additional royalties due, plus late payment interest calculated under 
Sec. Sec.  1218.54 and 1218.102 of this chapter.
    (3) A determination that 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 that ONRR issues is not binding on ONRR, delegated 
States, or you with respect to the specific situation addressed in the 
guidance.
    (1) Guidance and ONRR's decision whether or not to issue guidance 
or to request an Assistant Secretary determination, or neither, under 
paragraph (b) of this section, are not appealable decisions or orders 
under 30 CFR part 1290.
    (2) If you receive an order requiring you to pay royalty on the 
same basis as the guidance, you may appeal that order under 30 CFR part 
1290.
    (e) ONRR or the Assistant Secretary may use any of the applicable 
criteria in this subpart to provide guidance or to make a 
determination.
    (f) A change in an applicable statute or regulation on which ONRR 
based any guidance, or the Assistant Secretary based any determination, 
takes precedence over the determination or guidance after the effective 
date of the statute or regulation, regardless of whether ONRR or the 
Assistant Secretary modifies or rescinds the guidance or determination.
    (g) ONRR may make requests and replies under this section available 
to the public, subject to the confidentiality requirements under Sec.  
1206.149.


Sec.  1206.149  Does ONRR protect information that I provide?

    (a) Certain information that you or your affiliate submit(s) to 
ONRR regarding royalties on gas, including deductions and allowances, 
may be exempt from disclosure.
    (b) To the extent that applicable laws and regulations permit, ONRR 
will keep confidential any data that 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.


Sec.  1206.150  How do I determine royalty quantity and quality?

    (a)(1) You must calculate royalties based on the quantity and 
quality of unprocessed gas as measured at the point of royalty 
settlement that BLM or BSEE approves for onshore leases and OCS leases, 
respectively.
    (2) If you base the value of gas determined under this subpart on a 
quantity and/or quality that is different from the quantity and/or 
quality at the point of royalty settlement that BLM or BSEE approves, 
you must adjust that

[[Page 43384]]

value for the differences in quantity and/or quality.
    (b)(1) For residue gas and gas plant products, the quantity basis 
for computing royalties due is the monthly net output of the plant, 
even though residue gas and/or gas plant products may be in temporary 
storage.
    (2) If you value residue gas and/or gas plant products determined 
under this subpart on a quantity and/or quality of residue gas and/or 
gas plant products that is different from that which is attributable to 
a lease determined under paragraph (c) of this section, you must adjust 
that value for the differences in quantity and/or quality.
    (c) You must determine the quantity of the residue gas and gas 
plant products attributable to a lease based on the following 
procedure:
    (1) When you derive the net output of the processing plant from gas 
obtained from only one lease, you must base the quantity of the residue 
gas and gas plant products for royalty computation on the net output of 
the plant.
    (2) When you derive the net output of a processing plant from gas 
obtained from more than one lease producing gas of uniform content, you 
must base the quantity of the residue gas and gas plant products 
allocable to each lease on the same proportions as the ratios obtained 
by dividing the amount of gas delivered to the plant from each lease by 
the total amount of gas delivered from all leases.
    (3) When the net output of a processing plant is derived from gas 
obtained from more than one lease producing gas of non-uniform content:
    (i) You must determine the quantity of the residue gas allocable to 
each lease by multiplying the amount of gas delivered to the plant from 
the lease by the residue gas content of the gas, and dividing that 
arithmetical product by the sum of the similar arithmetical products 
separately obtained for all leases from which gas is delivered to the 
plant, and then multiplying the net output of the residue gas by the 
arithmetic quotient obtained.
    (ii) You must determine the net output of gas plant products 
allocable to each lease by multiplying the amount of gas delivered to 
the plant from the lease by the gas plant product content of the gas, 
dividing that arithmetical product by the sum of the similar 
arithmetical products separately obtained for all leases from which gas 
is delivered to the plant, and then multiplying the net output of each 
gas plant product by the arithmetic quotient obtained.
    (4) You may request prior ONRR approval of other methods for 
determining the quantity of residue gas and gas plant products 
allocable to each lease. If approved, you must apply that method to all 
gas production from Federal leases that is processed in the same plant. 
You must do so beginning with the production month following the month 
when ONRR received your request to use another method.
    (d)(1) You may not make any deductions from the royalty volume or 
royalty value for actual or theoretical losses. Any actual loss of 
unprocessed gas that you sustain before the royalty settlement meter or 
measurement point is not subject to royalty if BLM or BSEE, whichever 
is appropriate, determines that such loss was unavoidable.
    (2) Except as provided in paragraph (d)(1) of this section and 
Sec.  1202.151(c) of this chapter, you must pay royalties due on 100 
percent of the volume determined under paragraphs (a) through (c) of 
this section. You may not reduce that determined volume for actual 
losses after you have determined the quantity basis, or for theoretical 
losses that you claim to have taken place. Royalties are due on 100 
percent of the value of the unprocessed gas, residue gas, and/or gas 
plant products, as provided in this subpart, less applicable 
allowances. You may not take any deduction from the value of the 
unprocessed gas, residue gas, and/or gas plant products to compensate 
for actual losses after you have determined the quantity basis or for 
theoretical losses that you claim to have taken place.


Sec.  1206.151  [Reserved]


Sec.  1206.152  What general transportation allowance requirements 
apply to me?

    (a) ONRR will allow a deduction for the reasonable, actual costs to 
transport residue gas, gas plant products, or unprocessed gas from the 
lease to the point off of the lease under Sec.  1206.153 or Sec.  
1206.154, as applicable. You may not deduct transportation costs that 
you incur when moving a particular volume of production to reduce 
royalties that you owe on production for which you did not incur those 
costs. This paragraph applies when:
    (1) You value unprocessed gas under Sec.  1206.141(b) or residue 
gas and gas plant products under Sec.  1206.142(b) based on a sale at a 
point off of the lease, unit, or communitized area where the residue 
gas, gas plant products, or unprocessed gas is produced; and
    (2)(i) The movement to the sales point is not gathering.
    (ii) For gas produced on the OCS, the movement of gas from the 
wellhead to the first platform is not transportation.
    (b) You must calculate the deduction for transportation costs based 
on your or your affiliate's cost of transporting each product through 
each individual transportation system. If your or your affiliate's 
transportation contract includes more than one product in a gaseous 
phase, you must allocate costs consistently and equitably to each of 
the products transported. Your allocation must use the same proportion 
as the ratio of the volume of each product (excluding waste products 
with no value) to the volume of all products in the gaseous phase 
(excluding waste products with no value).
    (1) You may not take an allowance for transporting lease production 
that is not royalty-bearing.
    (2) You may propose to ONRR a prospective cost allocation method 
based on the values of the products transported. ONRR will approve the 
method if it is consistent with the purposes of the regulations in this 
subpart.
    (3) You may use your proposed procedure to calculate a 
transportation allowance beginning with the production month following 
the month when ONRR received your proposed procedure until ONRR accepts 
or rejects your cost allocation. If ONRR rejects your cost allocation, 
you must amend your Form ONRR-2014 for the months when you used the 
rejected method and pay any additional royalty due, plus late payment 
interest calculated under Sec. Sec.  1218.54 and 1218.102 of this 
chapter.
    (c)(1) Where you or your affiliate transport(s) both gaseous and 
liquid products through the same transportation system, you must 
propose a cost allocation procedure to ONRR.
    (2) You may use your proposed procedure to calculate a 
transportation allowance until ONRR accepts or rejects your cost 
allocation. If ONRR rejects your cost allocation, you must amend your 
Form ONRR-2014 for the months when you used the rejected method and pay 
any additional royalty due, plus late payment interest calculated under 
Sec. Sec.  1218.54 and 1218.102 of this chapter.
    (3) You must submit your initial proposal, including all available 
data, within three months after you first claim the allocated 
deductions on Form ONRR-2014.
    (d) If you value unprocessed gas under Sec.  1206.141(c) or residue 
gas and gas plant products under Sec.  1206.142 (d), you may not take a 
transportation allowance.
    (e)(1) Your transportation allowance may not exceed 50 percent of 
the value of the residue gas, gas plant products, or unprocessed gas as 
determined under Sec.  1206.141 or Sec.  1206.142.
    (2) If ONRR approved your request to take a transportation 
allowance in

[[Page 43385]]

excess of the 50-percent limitation under former Sec.  1206.156(c)(3), 
that approval is terminated as of January 1, 2017.
    (f) You must express transportation allowances for residue gas, gas 
plant products, or unprocessed gas as a dollar-value equivalent. If 
your or your affiliate's payments for transportation under a contract 
are not on a dollar-per-unit basis, you must convert whatever 
consideration that you or your affiliate are/is paid to a dollar-value 
equivalent.
    (g) ONRR may determine your transportation allowance under Sec.  
1206.144 because:
    (1) There is misconduct by or between the contracting parties;
    (2) ONRR determines that the consideration that you or your 
affiliate paid under an arm's-length transportation contract does not 
reflect the reasonable cost of the transportation because you breached 
your duty to market the gas, residue gas, or gas plant products for the 
mutual benefit of yourself and the lessor by transporting your gas, 
residue gas, or gas plant products at a cost that is unreasonably high. 
We may consider a transportation allowance unreasonably high if it is 
10 percent higher than the highest reasonable measures of 
transportation costs, including, but not limited to, transportation 
allowances reported to ONRR and tariffs for gas, residue gas, or gas 
plant products transported through the same system; or
    (3) ONRR cannot determine if you properly calculated a 
transportation allowance under Sec.  1206.153 or Sec.  1206.154 for any 
reason, including, but not limited to, your or your affiliate's failure 
to provide documents that ONRR requests under 30 CFR part 1212, subpart 
B.
    (h) You do not need ONRR's approval before reporting a 
transportation allowance.


Sec.  1206.153  How do I determine a transportation allowance if I have 
an arm's-length transportation contract?

    (a)(1) If you or your affiliate incur transportation costs under an 
arm's-length transportation contract, you may claim a transportation 
allowance for the reasonable, actual costs incurred, as more fully 
explained in paragraph (b) of this section, except as provided in Sec.  
1206.152(g) and subject to the limitation in Sec.  1206.152(e).
    (2) You must be able to demonstrate that your or your affiliate's 
contract is arm's-length.
    (b) Subject to the requirements of paragraph (c) of this section, 
you may include, but are not limited to, the following costs to 
determine your transportation allowance under paragraph (a) of this 
section; you may not use any cost as a deduction that duplicates all or 
part of any other cost that you use under this section:
    (1) Firm demand charges paid to pipelines. You may deduct firm 
demand charges or capacity reservation fees that you or your affiliate 
paid to a pipeline, including charges or fees for unused firm capacity 
that you or your affiliate have not sold before you report your 
allowance. If you or your affiliate receive(s) a payment from any party 
for release or sale of firm capacity after reporting a transportation 
allowance that included the cost of that unused firm capacity, or if 
you or your affiliate receive(s) a payment or credit from the pipeline 
for penalty refunds, rate case refunds, or other reasons, you must 
reduce the firm demand charge claimed on Form ONRR-2014 by the amount 
of that payment. You must modify Form ONRR-2014 by the amount received 
or credited for the affected reporting period and pay any resulting 
royalty due, plus late payment interest calculated under Sec. Sec.  
1218.54 and 1218.102 of this chapter.
    (2) Gas Supply Realignment (GSR) costs. The GSR costs result from a 
pipeline reforming or terminating supply contracts with producers in 
order to implement the restructuring requirements of FERC Orders in 18 
CFR part 284.
    (3) Commodity charges. The commodity charge allows the pipeline to 
recover the costs of providing service.
    (4) Wheeling costs. Hub operators charge a wheeling cost for 
transporting gas from one pipeline to either the same or another 
pipeline through a market center or hub. A hub is a connected manifold 
of pipelines through which a series of incoming pipelines are 
interconnected to a series of outgoing pipelines.
    (5) Gas Research Institute (GRI) fees. The GRI conducts research, 
development, and commercialization programs on natural gas-related 
topics for the benefit of the U.S. gas industry and gas customers. GRI 
fees are allowable, provided that such fees are mandatory in FERC-
approved tariffs.
    (6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to 
pipelines to pay for its operating expenses.
    (7) Payments (either volumetric or in value) for actual or 
theoretical losses. Theoretical losses are not deductible in 
transportation arrangements unless the transportation allowance is 
based on arm's-length transportation rates charged under a FERC or 
State regulatory-approved tariff. If you or your affiliate receive(s) 
volumes or credit for line gain, you must reduce your transportation 
allowance accordingly and pay any resulting royalties plus late payment 
interest calculated under Sec. Sec.  1218.54 and 1218.102 of this 
chapter;
    (8) Temporary storage services. This includes short-duration 
storage services that market centers or hubs (commonly referred to as 
``parking'' or ``banking'') offer or other temporary storage services 
that pipeline transporters provide, whether actual or provided as a 
matter of accounting. Temporary storage is limited to 30 days or fewer.
    (9) Supplemental costs for compression, dehydration, and treatment 
of gas. ONRR allows these costs only if such services are required for 
transportation and exceed the services necessary to place production 
into marketable condition required under Sec.  1206.146.
    (10) Costs of surety. You may deduct the costs of securing a letter 
of credit, or other surety, that the pipeline requires you or your 
affiliate, as a shipper, to maintain under a transportation contract.
    (11) Hurricane surcharges. You may deduct hurricane surcharges that 
you or your affiliate actually pay(s).
    (c) You may not include the following costs to determine your 
transportation allowance under paragraph (a) of this section:
    (1) Fees or costs incurred for storage. This includes storing 
production in a storage facility, whether on or off of the lease, for 
more than 30 days.
    (2) Aggregator/marketer fees. This includes fees that you or your 
affiliate pay(s) to another person (including your affiliates) to 
market your gas, including purchasing and reselling the gas or finding 
or maintaining a market for the gas production.
    (3) Penalties that you or your affiliate incur(s) as a shipper. 
These penalties include, but are not limited to:
    (i) Over-delivery cash-out penalties. This includes the difference 
between the price that the pipeline pays to you or your affiliate for 
over-delivered volumes outside of the tolerances and the price that you 
or your affiliate receive(s) for over-delivered volumes within the 
tolerances.
    (ii) Scheduling penalties. This includes penalties that you or your 
affiliate incur(s) for differences between daily volumes delivered into 
the pipeline and volumes scheduled or nominated at a receipt or 
delivery point.
    (iii) Imbalance penalties. This includes penalties that you or your 
affiliate incur(s) (generally on a monthly basis) for differences 
between volumes delivered into the pipeline and volumes

[[Page 43386]]

scheduled or nominated at a receipt or delivery point.
    (iv) Operational penalties. This includes fees that you or your 
affiliate incur(s) for violation of the pipeline's curtailment or 
operational orders issued to protect the operational integrity of the 
pipeline.
    (4) Intra-hub transfer fees. These are fees that you or your 
affiliate pay(s) to hub operators for administrative services (such as 
title transfer tracking) necessary to account for the sale of gas 
within a hub.
    (5) Fees paid to brokers. This includes fees that you or your 
affiliate pay(s) to parties who arrange marketing or transportation, if 
such fees are separately identified from aggregator/marketer fees.
    (6) Fees paid to scheduling service providers. This includes fees 
that you or your affiliate pay(s) to parties who provide scheduling 
services, if such fees are separately identified from aggregator/
marketer fees.
    (7) Internal costs. This includes salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to 
schedule, nominate, and account for the sale or movement of production.
    (8) Other non-allowable costs. Any cost you or your affiliate 
incur(s) for services that you are required to provide at no cost to 
the lessor, including, but not limited to, costs to place your gas, 
residue gas, or gas plant products into marketable condition disallowed 
under Sec.  1206.146 and costs of boosting residue gas disallowed under 
Sec.  1202.151(b).
    (d) If you have no written contract for the transportation of gas, 
then ONRR will determine your transportation allowance under Sec.  
1206.144. You may not use this paragraph (d) if you or your affiliate 
perform(s) your own transportation.
    (1) You must propose to ONRR a method to determine the allowance 
using the procedures in Sec.  1206.148(a).
    (2) You may use that method to determine your allowance until ONRR 
issues its determination.


Sec.  1206.154  How do I determine a transportation allowance if I have 
a non-arm's-length transportation contract?

    (a) This section applies if you or your affiliate do(es) not have 
an arm's-length transportation contract, including situations where you 
or your affiliate provide your own transportation services. You must 
calculate your transportation allowance based on your or your 
affiliate's reasonable, actual costs for transportation during the 
reporting period using the procedures prescribed in this section.
    (b) Your or your affiliate's actual costs may include:
    (1) Capital costs and operating and maintenance expenses under 
paragraphs (e), (f), and (g) of this section.
    (2) Overhead under paragraph (h) of this section.
    (3) Depreciation and a return on undepreciated capital investment 
under paragraph (i)(1) of this section, or you may elect to use a cost 
equal to a return on the initial depreciable capital investment in the 
transportation system under paragraph (i)(2) of this section. After you 
have elected to use either method for a transportation system, you may 
not later elect to change to the other alternative without ONRR's 
approval. If ONRR accepts your request to change methods, you may use 
your changed method beginning with the production month following the 
month when ONRR received your change request.
    (4) A return on the reasonable salvage value under paragraph 
(i)(1)(iii) of this section, after you have depreciated the 
transportation system to its reasonable salvage value.
    (c)(1) To the extent not included in costs identified in paragraphs 
(e) through (g) of this section, if you or your affiliate incur(s) the 
actual transportation costs listed under Sec.  1206.153(b)(2), (5), and 
(6) under your or your affiliate's non-arm's-length contract, you may 
include those costs in your calculations under this section. You may 
not include any of the other costs identified under Sec.  1206.153(b).
    (2) You may not include in your calculations under this section any 
of the non-allowable costs listed under Sec.  1206.153(c).
    (d) You may not use any cost as a deduction that duplicates all or 
part of any other cost that you use under this section.
    (e) Allowable capital investment costs are generally those for 
depreciable fixed assets (including costs of delivery and installation 
of capital equipment) that are an integral part of the transportation 
system.
    (f) Allowable operating expenses include the following:
    (1) Operations supervision and engineering.
    (2) Operations labor.
    (3) Fuel.
    (4) Utilities.
    (5) Materials.
    (6) Ad valorem property taxes.
    (7) Rent.
    (8) Supplies.
    (9) Any other directly allocable and attributable operating expense 
that you can document.
    (g) Allowable maintenance expenses include the following:
    (1) Maintenance of the transportation system.
    (2) Maintenance of equipment.
    (3) Maintenance labor.
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (h) Overhead, directly attributable and allocable to the operation 
and maintenance of the transportation system, is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (i)(1) To calculate depreciation and a return on undepreciated 
capital investment, you may elect to use either a straight-line 
depreciation method based on the life of equipment or on the life of 
the reserves that the transportation system services, or you may elect 
to use a unit-of-production method. After you make an election, you may 
not change methods without ONRR's approval. If ONRR accepts your 
request to change methods, you may use your changed method beginning 
with the production month following the month when ONRR received your 
change request.
    (i) A change in ownership of a transportation system will not alter 
the depreciation schedule that the original transporter/lessee 
established for the purposes of the allowance calculation.
    (ii) You may depreciate a transportation system only once with or 
without a change in ownership.
    (iii)(A) To calculate the return on undepreciated capital 
investment, you may use an amount equal to the undepreciated capital 
investment in the transportation system multiplied by the rate of 
return that you determine under paragraph (i)(3) of this section.
    (B) After you have depreciated a transportation system to the 
reasonable salvage value, you may continue to include in the allowance 
calculation a cost equal to the reasonable salvage value multiplied by 
a rate of return under paragraph (i)(3) of this section.
    (2) As an alternative to using depreciation and a return on 
undepreciated capital investment, as provided under paragraph (b)(3) of 
this section, you may use as a cost an amount equal to the allowable 
initial capital investment in the transportation system multiplied by 
the rate of return determined under paragraph (i)(3) of this section. 
You may not include depreciation in your allowance.
    (3) The rate of return is the industrial rate associated with 
Standard & Poor's BBB rating.
    (i) You must use the monthly average BBB rate that Standard & 
Poor's

[[Page 43387]]

publishes for the first month for which the allowance is applicable.
    (ii) You must re-determine the rate at the beginning of each 
subsequent calendar year.


Sec.  1206.155  What are my reporting requirements under an arm's-
length transportation contract?

    (a) You must use a separate entry on Form ONRR-2014 to notify ONRR 
of an allowance based on transportation costs that you or your 
affiliate incur(s).
    (b) ONRR may require you or your affiliate to submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents.
    (c) You can find recordkeeping requirements in parts 1207 and 1212 
of this chapter.


Sec.  1206.156  What are my reporting requirements under a non-arm's-
length transportation contract?

    (a) You must use a separate entry on Form ONRR-2014 to notify ONRR 
of an allowance based on non-arm's-length transportation costs that you 
or your affiliate incur(s).
    (b)(1) For new non-arm's-length transportation facilities or 
arrangements, you must base your initial deduction on estimates of 
allowable transportation costs for the applicable period.
    (2) You must use your or your affiliate's most recently available 
operations data for the transportation system as your estimate. If such 
data is not available, you must use estimates based on data for similar 
transportation systems.
    (3) Section 1206.158 applies when you amend your report based on 
your actual costs.
    (c) ONRR may require you or your affiliate to submit all data used 
to calculate the allowance deduction. You can find recordkeeping 
requirements in parts 1207 and 1212 of this chapter.


Sec.  1206.157  What interest and penalties apply if I improperly 
report a transportation allowance?

    (a)(1) If ONRR determines that you took an unauthorized 
transportation allowance, then you must pay any additional royalties 
due, plus late payment interest calculated under Sec. Sec.  1218.54 and 
1218.102 of this chapter.
    (2) If you understated your transportation allowance, you may be 
entitled to a credit, with interest.
    (b) If you deduct a transportation allowance on Form ONRR-2014 that 
exceeds 50 percent of the value of the gas, residue gas, or gas plant 
products transported, you must pay late payment interest on the excess 
allowance amount taken from the date when that amount is taken until 
the date when you pay the additional royalties due.
    (c) If you improperly net a transportation allowance against the 
sales value of the residue gas, gas plant products, or unprocessed gas 
instead of reporting the allowance as a separate entry on Form ONRR-
2014, ONRR may assess a civil penalty under 30 CFR part 1241.


Sec.  1206.158  What reporting adjustments must I make for 
transportation allowances?

    (a) If your actual transportation allowance is less than the amount 
that 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 Sec. Sec.  1218.54 and 1218.102 of 
this chapter from the date when you took the deduction to the date when 
you repay the difference.
    (b) If the actual transportation allowance is greater than the 
amount that you claimed on Form ONRR-2014 for any month during the 
period reported on the allowance form, you are entitled to a credit, 
plus interest.


Sec.  1206.159  What general processing allowances requirements apply 
to me?

    (a)(1) When you value any gas plant product under Sec.  
1206.142(c), you may deduct from the value the reasonable, actual costs 
of processing.
    (2) You do not need ONRR's approval before reporting a processing 
allowance.
    (b) You must allocate processing costs among the gas plant 
products. You must determine a separate processing allowance for each 
gas plant product and processing plant relationship. ONRR considers 
NGLs to be one product.
    (c)(1) You may not apply the processing allowance against the value 
of the residue gas.
    (2) The processing allowance deduction on the basis of an 
individual product may not exceed 66\2/3\ percent of the value of each 
gas plant product determined under Sec.  1206.142(c). Before you 
calculate the 66\2/3\-percent limit, you must first reduce the value 
for any transportation allowances related to post-processing 
transportation authorized under Sec.  1206.152.
    (3) If ONRR approved your request to take a processing allowance in 
excess of the limitation in paragraph (c)(2) of this section under 
former Sec.  1206.158(c)(3), that approval is terminated as of January 
1, 2017.
    (4) If ONRR approved your request to take an extraordinary cost 
processing allowance under former Sec.  1206.158(d), ONRR terminates 
that approval as of January 1, 2017.
    (d)(1) ONRR will not allow a processing cost deduction for the 
costs of placing lease products in marketable condition, including 
dehydration, separation, compression, or storage, even if those 
functions are performed off the lease or at a processing plant.
    (2) Where gas is processed for the removal of acid gases, commonly 
referred to as ``sweetening,'' ONRR will not allow processing cost 
deductions for such costs unless the acid gases removed are further 
processed into a gas plant product.
    (i) In such event, you are eligible for a processing allowance 
determined under this subpart.
    (ii) ONRR will not grant any processing allowance for processing 
lease production that is not royalty bearing.
    (e) ONRR may determine your processing allowance under Sec.  
1206.144 because:
    (1) There is misconduct by or between the contracting parties;
    (2) ONRR determines that the consideration that you or your 
affiliate paid under an arm's-length processing contract does not 
reflect the reasonable cost of the processing because you breached your 
duty to market the gas, residue gas, or gas plant products for the 
mutual benefit of yourself and the lessor by processing your gas, 
residue gas, or gas plant products at a cost that is unreasonably high. 
We may consider a processing allowance unreasonably high if it is 10 
percent higher than the highest reasonable measures of processing 
costs, including, but not limited to, processing allowances reported to 
ONRR; or
    (3) ONRR cannot determine if you properly calculated a processing 
allowance under Sec.  1206.160 or Sec.  1206.161 for any reason, 
including, but not limited to, your or your affiliate's failure to 
provide documents that ONRR requests under 30 CFR part 1212, subpart B.


Sec.  1206.160  How do I determine a processing allowance if I have an 
arm's-length processing contract?

    (a)(1) If you or your affiliate incur processing costs under an 
arm's-length processing contract, you may claim a processing allowance 
for the reasonable, actual costs incurred, as more fully explained in 
paragraph (b) of this section, except as provided in paragraphs 
(a)(3)(i) and (a)(3)(ii) of this section and subject to the limitation 
in Sec.  1206.159(c)(2).
    (2) You must be able to demonstrate that your or your affiliate's 
contract is arm's-length.
    (b)(1) If your or your affiliate's arm's-length processing contract 
includes

[[Page 43388]]

more than one gas plant product, and you can determine the processing 
costs for each product based on the contract, then you must determine 
the processing costs for each gas plant product under the contract.
    (2) If your or your affiliate's arm's-length processing contract 
includes more than one gas plant product, and you cannot determine the 
processing costs attributable to each product from the contract, you 
must propose an allocation procedure to ONRR.
    (i) You may use your proposed allocation procedure until ONRR 
issues its determination.
    (ii) You must submit all relevant data to support your proposal.
    (iii) ONRR will determine the processing allowance based upon your 
proposal and any additional information that ONRR deems necessary.
    (iv) You must submit the allocation proposal within three months of 
claiming the allocated deduction on Form ONRR-2014.
    (3) You may not take an allowance for the costs of processing lease 
production that is not royalty-bearing.
    (4) If your or your affiliate's payments for processing under an 
arm's-length contract are not based on a dollar-per-unit basis, you 
must convert whatever consideration that you or your affiliate paid to 
a dollar-value equivalent.
    (c) If you have no written contract for the arm's-length processing 
of gas, then ONRR will determine your processing allowance under Sec.  
1206.144. You may not use this paragraph (c) if you or your affiliate 
perform(s) your own processing.
    (1) You must propose to ONRR a method to determine the allowance 
using the procedures in Sec.  1206.148(a).
    (2) You may use that method to determine your allowance until ONRR 
issues a determination.


Sec.  1206.161  How do I determine a processing allowance if I have a 
non-arm's-length processing contract?

    (a) This section applies if you or your affiliate do(es) not have 
an arm's-length processing contract, including situations where you or 
your affiliate provide your own processing services. You must calculate 
your processing allowance based on your or your affiliate's reasonable, 
actual costs for processing during the reporting period using the 
procedures prescribed in this section.
    (b) Your or your affiliate's actual costs may include:
    (1) Capital costs and operating and maintenance expenses under 
paragraphs (d), (e), and (f) of this section.
    (2) Overhead under paragraph (g) of this section.
    (3) Depreciation and a return on undepreciated capital investment 
in accordance with paragraph (h)(1) of this section, or you may elect 
to use a cost equal to the initial depreciable capital investment in 
the processing plant under paragraph (h)(2) of this section. After you 
have elected to use either method for a processing plant, you may not 
later elect to change to the other alternative without ONRR's approval. 
If ONRR accepts your request to change methods, you may use your 
changed method beginning with the production month following the month 
when ONRR received your change request.
    (4) A return on the reasonable salvage value under paragraph 
(h)(1)(iii) of this section, after you have depreciated the processing 
plant to its reasonable salvage value.
    (c) You may not use any cost as a deduction that duplicates all or 
part of any other cost that you use under this section.
    (d) Allowable capital investment costs are generally those for 
depreciable fixed assets (including costs of delivery and installation 
of capital equipment), which are an integral part of the processing 
plant.
    (e) Allowable operating expenses include the following:
    (1) Operations supervision and engineering.
    (2) Operations labor.
    (3) Fuel.
    (4) Utilities.
    (5) Materials.
    (6) Ad valorem property taxes.
    (7) Rent.
    (8) Supplies.
    (9) Any other directly allocable and attributable operating expense 
that you can document.
    (f) Allowable maintenance expenses may include the following:
    (1) Maintenance of the processing plant.
    (2) Maintenance of equipment.
    (3) Maintenance labor.
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (g) Overhead, directly attributable and allocable to the operation 
and maintenance of the processing plant, is an allowable expense. State 
and Federal income taxes and severance taxes and other fees, including 
royalties, are not allowable expenses.
    (h)(1) To calculate depreciation and a return on undepreciated 
capital investment, you may elect to use either a straight-line 
depreciation method based on the life of equipment or on the life of 
the reserves that the processing plant services, or you may elect to 
use a unit-of-production method. After you make an election, you may 
not change methods without ONRR's approval. If ONRR accepts your 
request to change methods, you may use your changed method beginning 
with the production month following the month when ONRR received your 
change request.
    (i) A change in ownership of a processing plant will not alter the 
depreciation schedule that the original processor/lessee established 
for purposes of the allowance calculation.
    (ii) You may depreciate a processing plant only once with or 
without a change in ownership.
    (iii)(A) To calculate a return on undepreciated capital investment, 
you may use an amount equal to the undepreciated capital investment in 
the processing plant multiplied by the rate of return that you 
determine under paragraph (h)(3) of this section.
    (B) After you have depreciated a processing plant to its reasonable 
salvage value, you may continue to include in the allowance calculation 
a cost equal to the reasonable salvage value multiplied by a rate of 
return under paragraph (h)(3) of this section.
    (2) You may use as a cost an amount equal to the allowable initial 
capital investment in the processing plant multiplied by the rate of 
return determined under paragraph (h)(3) of this section. You may not 
include depreciation in your allowance.
    (3) The rate of return is the industrial rate associated with 
Standard & Poor's BBB rating.
    (i) You must use the monthly average BBB rate that Standard & 
Poor's publishes for the first month for which the allowance is 
applicable.
    (ii) You must re-determine the rate at the beginning of each 
subsequent calendar year.
    (i)(1) You must determine the processing allowance for each gas 
plant product based on your or your affiliate's reasonable and actual 
cost of processing the gas. You must base your allocation of costs to 
each gas plant product upon generally accepted accounting principles.
    (2) You may not take an allowance for processing lease production 
that is not royalty-bearing.
    (j) You may apply for an exception from the requirement to 
calculate actual costs under paragraphs (a) and (b) of this section.
    (1) ONRR will grant the exception if:
    (i) You have or your affiliate has arm's-length contracts for 
processing other gas production at the same processing plant; and
    (ii) At least 50 percent of the gas processed annually at the plant 
is processed under arm's-length processing contracts.

[[Page 43389]]

    (2) If ONRR grants the exception, you must use as your processing 
allowance the volume-weighted average prices charged to other persons 
under arm's-length contracts for processing at the same plant.


Sec.  1206.162  What are my reporting requirements under an arm's-
length processing contract?

    (a) You must use a separate entry on Form ONRR-2014 to notify ONRR 
of an allowance based on arm's-length processing costs that you or your 
affiliate incur(s).
    (b) ONRR may require you or your affiliate to submit arm's-length 
processing contracts, production agreements, operating agreements, and 
related documents.
    (c) You can find recordkeeping requirements in parts 1207 and 1212 
of this chapter.


Sec.  1206.163  What are my reporting requirements under a non-arm's-
length processing contract?

    (a) You must use a separate entry on Form ONRR-2014 to notify ONRR 
of an allowance based on non-arm's-length processing costs that you or 
your affiliate incur(s).
    (b)(1) For new non-arm's-length processing facilities or 
arrangements, you must base your initial deduction on estimates of 
allowable gas processing costs for the applicable period.
    (2) You must use your or your affiliate's most recently available 
operations data for the processing plant as your estimate, if 
available. If such data is not available, you must use estimates based 
on data for similar processing plants.
    (3) Section 1206.165 applies when you amend your report based on 
your actual costs.
    (c) ONRR may require you or your affiliate to submit all data used 
to calculate the allowance deduction. You can find recordkeeping 
requirements in parts 1207 and 1212 of this chapter.
    (d) If you are authorized under Sec.  1206.161(j) to use an 
exception to the requirement to calculate your actual processing costs, 
you must follow the reporting requirements of Sec.  1206.162.


Sec.  1206.164  What interest and penalties apply if I improperly 
report a processing allowance?

    (a)(1) If ONRR determines that you took an unauthorized processing 
allowance, then you must pay any additional royalties due, plus late 
payment interest calculated under Sec. Sec.  1218.54 and 1218.102 of 
this chapter.
    (2) If you understated your processing allowance, you may be 
entitled to a credit, with interest.
    (b) If you deduct a processing allowance on Form ONRR-2014 that 
exceeds 66\2/3\ percent of the value of a gas plant product, you must 
pay late payment interest on the excess allowance amount taken from the 
date when that amount is taken until the date when you pay the 
additional royalties due.
    (c) If you improperly net a processing allowance against the sales 
value of a gas plant product instead of reporting the allowance as a 
separate entry on Form ONRR-2014, ONRR may assess a civil penalty under 
30 CFR part 1241.


Sec.  1206.165  What reporting adjustments must I make for processing 
allowances?

    (a) If your actual processing allowance is less than the amount 
that 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 Sec. Sec.  1218.54 and 1218.102 of 
this chapter from the date when you took the deduction to the date when 
you repay the difference.
    (b) If the actual processing allowance is greater than the amount 
that you claimed on Form ONRR-2014 for any month during the period 
reported on the allowance form, you are entitled to a credit, plus 
interest.

0
8. Revise subpart F to read as follows:

Subpart F--Federal Coal

Sec.
1206.250 What is the purpose and scope of this subpart?
1206.251 How do I determine royalty quantity and quality?
1206.252 How do I calculate royalty value for coal that I or my 
affiliate sell(s) under an arm's-length or non-arm's-length 
contract?
1206.253 How will ONRR determine if my royalty payments are correct?
1206.254 How will ONRR determine the value of my coal for royalty 
purposes?
1206.255 What records must I keep in order to support my 
calculations of royalty under this subpart?
1206.256 What are my responsibilities to place production into 
marketable condition and to market production?
1206.257 When is an ONRR audit, review, reconciliation, monitoring, 
or other like process considered final?
1206.258 How do I request a valuation determination?
1206.259 Does ONRR protect information that I provide?
1206.260 What general transportation allowance requirements apply to 
me?
1206.261 How do I determine a transportation allowance if I have an 
arm's-length transportation contract or no written arm's-length 
contract?
1206.262 How do I determine a transportation allowance if I do not 
have an arm's-length transportation contract?
1206.263 What are my reporting requirements under an arm's-length 
transportation contract?
1206.264 What are my reporting requirements under a non-arm's-length 
transportation contract?
1206.265 What interest and penalties apply if I improperly report a 
transportation allowance?
1206.266 What reporting adjustments must I make for transportation 
allowances?
1206.267 What general washing allowance requirements apply to me?
1206.268 How do I determine washing allowances if I have an arm's-
length washing contract or no written arm's-length contract?
1206.269 How do I determine washing allowances if I do not have an 
arm's-length washing contract?
1206.270 What are my reporting requirements under an arm's-length 
washing contract?
1206.271 What are my reporting requirements under a non-arm's-length 
washing contract?
1206.272 What interest and penalties apply if I improperly report a 
washing allowance?
1206.273 What reporting adjustments must I make for washing 
allowances?

Subpart F--Federal Coal


Sec.  1206.250  What is the purpose and scope of this subpart?

    (a) This subpart applies to all coal produced from Federal coal 
leases. It explains how you, as the lessee, must calculate the value of 
production for royalty purposes consistent with the mineral leasing 
laws, other applicable laws, and lease terms.
    (b) The terms ``you'' and ``your'' in this subpart refer to the 
lessee.
    (c) If the regulations in this subpart are inconsistent with a(an): 
Federal statute; settlement agreement between the United States and a 
lessee resulting from administrative or judicial litigation; written 
agreement between the lessee and ONRR's 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 express provision of a coal lease subject to this subpart, then the 
statute, settlement agreement, written agreement, or lease provision 
will govern to the extent of the inconsistency.
    (d) ONRR may audit and order you to adjust all royalty payments.


Sec.  1206.251  How do I determine royalty quantity and quality?

    (a) You must calculate royalties based on the quantity and quality 
of coal at the royalty measurement point that ONRR and BLM jointly 
determine.
    (b) You must measure coal in short tons using the methods that BLM

[[Page 43390]]

prescribes for Federal coal leases under 43 CFR part 3000. You must 
report coal quantity on appropriate forms required in 30 CFR part 
1210--Forms and Reports.
    (c)(1) You are not required to pay royalties on coal that you 
produce and add to stockpiles or inventory until you use, sell, or 
otherwise finally dispose of such coal.
    (2) ONRR may request that BLM require you to increase your lease 
bond if BLM determines that stockpiles or inventory are excessive such 
that they increase the risk of resource degradation.
    (d) You must pay royalty at the rate specified in your lease at the 
time when you use, sell, or otherwise finally dispose of the coal.
    (e) You must allocate washed coal by attributing the washed coal to 
the leases from which it was extracted.
    (1) If the wash plant washes coal from only one lease, the quantity 
of washed coal allocable to the lease is the total output of washed 
coal from the plant.
    (2) If the wash plant washes coal from more than one lease, you 
must determine the tonnage of washed coal attributable to each lease 
by:
    (i) First, calculating the input ratio of washed coal allocable to 
each lease by dividing the tonnage of coal input to the wash plant from 
each lease by the total tonnage of coal input to the wash plant from 
all leases.
    (ii) Second, multiplying the input ratio derived under paragraph 
(e)(2)(i) of this section by the tonnage of total output of washed coal 
from the plant.


Sec.  1206.252  How do I calculate royalty value for coal that I or my 
affiliate sell(s) under an arm's-length or non-arm's-length contract?

    (a) The value of coal under this section for royalty purposes is 
the gross proceeds accruing to you or your affiliate under the first 
arm's-length contract, less an applicable transportation allowance 
determined under Sec. Sec.  1206.260 through 1206.262 and washing 
allowance under Sec. Sec.  1206.267 through 1206.269. You must use this 
paragraph (a) to value coal when:
    (1) You sell under an arm's-length contract; or
    (2) You sell or transfer to your affiliate or another person under 
a non-arm's-length contract, and that affiliate or person, or another 
affiliate of either of them, then sells the coal under an arm's-length 
contract.
    (b) If you have no contract for the sale of coal subject to this 
section because you or your affiliate used the coal in a power plant 
that you or your affiliate own(s) for the generation and sale of 
electricity, one of the following applies:
    (1) You or your affiliate sell(s) the electricity, then the value 
of the coal subject to this section, for royalty purposes, is the gross 
proceeds accruing to you for the power plant's arm's-length sales of 
the electricity less applicable transportation and washing deductions 
determined under Sec. Sec.  1206.260 through 1206.262 and Sec. Sec.  
1206.267 through 1206.269 and, if applicable, transmission and 
generation deductions determined under Sec. Sec.  1206.353 and 
1206.354.
    (2) You or your affiliate do(es) not sell the electricity at arm's-
length (for example you or your affiliate deliver(s) the electricity 
directly to the grid), then ONRR will determine the value of the coal 
under Sec.  1206.254.
    (i) You must propose to ONRR a method to determine the value using 
the procedures in Sec.  1206.258(a).
    (ii) You may use that method to determine value, for royalty 
purposes, until ONRR issues a determination.
    (iii) After ONRR issues a determination, you must make the 
adjustments under Sec.  1206.253(a)(2).
    (c) If you are a coal cooperative, or a member of a coal 
cooperative, one of the following applies:
    (1) You sell or transfer coal to another member of the coal 
cooperative, and that member of the coal cooperative then sells the 
coal under an arm's-length contract, then you must value the coal under 
paragraph (a) of this section.
    (2) You sell or transfer coal to another member of the coal 
cooperative, and you, the coal cooperative, or another member of the 
coal cooperative use the coal in a power plant for the generation and 
sale of electricity, then you must value the coal under paragraph (b) 
of this section.
    (d) If you are entitled to take a washing allowance and 
transportation allowance for royalty purposes under this section, under 
no circumstances may the washing allowance plus the transportation 
allowance reduce the royalty value of the coal to zero.
    (e) The values in this section do not apply if ONRR decides to 
value your coal under Sec.  1206.254.


Sec.  1206.253  How will ONRR determine if my royalty payments are 
correct?

    (a)(1) ONRR may monitor, review, and audit the royalties that you 
report. If ONRR determines that your reported value is inconsistent 
with the requirements of this subpart, ONRR will direct you to use a 
different measure of royalty value, or decide your value, under Sec.  
1206.254.
    (2) If ONRR directs you to use a different royalty value, you must 
either pay any underpaid royalties due, plus late payment interest 
calculated under Sec.  1218.202 of this chapter, or report a credit 
for--or request a refund of--any overpaid royalties.
    (b) When the provisions in this subpart refer to gross proceeds, in 
conducting reviews and audits, ONRR will examine if your or your 
affiliate's contract reflects the total consideration that is actually 
transferred, either directly or indirectly, from the buyer to you or 
your affiliate for the coal. If ONRR determines that a contract does 
not reflect the total consideration, ONRR may decide your value under 
Sec.  1206.254.
    (c) ONRR may decide to value your coal under Sec.  1206.254 if ONRR 
determines that the gross proceeds accruing to you or your affiliate 
under a contract do not reflect reasonable consideration because:
    (1) There is misconduct by or between the contracting parties;
    (2) You breached your duty to market the coal for the mutual 
benefit of yourself and the lessor by selling your coal at a value that 
is unreasonably low. ONRR may consider a sales price unreasonably low 
if it is 10 percent less than the lowest other reasonable measures of 
market price, including, but not limited to, prices reported to ONRR 
for like-quality coal; or
    (3) ONRR cannot determine if you properly valued your coal under 
Sec.  1206.252 for any reason, including, but not limited to, your or 
your affiliate's failure to provide documents to ONRR under 30 CFR part 
1212, subpart E.
    (d) You have the burden of demonstrating that your or your 
affiliate's contract is arm's-length.
    (e) ONRR may require you to certify that the provisions in your or 
your affiliate's contract include(s) all of the consideration that the 
buyer paid to you or your affiliate, either directly or indirectly, for 
the coal.
    (f)(1) Absent any contract revisions or amendments, 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 apply in a timely manner 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

[[Page 43391]]

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 in a timely manner, for a quantity of coal.
    (g)(1) You or your affiliate must make all contracts, contract 
revisions, or amendments in writing, and all parties to the contract 
must sign the contract, contract revisions, or amendments.
    (2) If you or your affiliate fail(s) to comply with paragraph 
(g)(1) of this section, ONRR may decide to value your coal under Sec.  
1206.254.
    (3) This provision applies notwithstanding any other provisions in 
this title 30 to the contrary.


Sec.  1206.254  How will ONRR determine the value of my coal for 
royalty purposes?

    If ONRR decides to value your coal for royalty purposes under Sec.  
1206.253, or any other provision in this subpart, then ONRR will 
determine value by considering any information that we deem relevant, 
which may include, but is not limited to:
    (a) The value of like-quality coal from the same mine, nearby 
mines, the same region, other regions, or washed in the same or nearby 
wash plant.
    (b) Public sources of price or market information that ONRR deems 
reliable, including, but not limited to, the price of electricity.
    (c) Information available to ONRR and information reported to us, 
including, but not limited to, on Form ONRR-4430.
    (d) Costs of transportation or washing, if ONRR determines that 
they are applicable.
    (e) Any other information that ONRR deems relevant regarding the 
particular lease operation or the salability of the coal.


Sec.  1206.255  What records must I keep in order to support my 
calculations of royalty under this subpart?

    If you value your coal under this subpart, you must retain all data 
relevant to the determination of the royalty that you paid. You can 
find recordkeeping requirements in parts 1207 and 1212 of this chapter.
    (a) You must show:
    (1) How you calculated the royalty value, including all allowable 
deductions; and
    (2) How you complied with this subpart.
    (b) Upon request, you must submit all data to ONRR. You must comply 
with any such requirement within the time that ONRR specifies.


Sec.  1206.256  What are my responsibilities to place production into 
marketable condition and to market production?

    (a) You must place coal in marketable condition and market the coal 
for the mutual benefit of the lessee and the lessor at no cost to the 
Federal Government.
    (b) If you use gross proceeds under an arm's-length contract in 
order to determine royalty, you must increase those gross proceeds to 
the extent that the purchaser, or any other person, provides certain 
services that you normally are responsible to perform in order to place 
the coal in marketable condition or to market the coal.


Sec.  1206.257  When is an ONRR audit, review, reconciliation, 
monitoring, or other like process considered final?

    Notwithstanding any provision in these regulations to the contrary, 
ONRR will not consider any audit, review, reconciliation, monitoring, 
or other like process that results in ONRR re-determining royalty due, 
under this subpart, final or binding as against the Federal government 
or its beneficiaries unless ONRR chooses to, in writing, formally close 
the audit period.


Sec.  1206.258  How do I request a valuation determination?

    (a) You may request a valuation determination from ONRR regarding 
any coal produced. Your request must:
    (1) Be in writing;
    (2) Identify specifically all leases involved, all interest owners 
of those leases, and the operator(s) for those leases;
    (3) Completely explain all relevant facts. You must inform ONRR of 
any changes to relevant facts that occur before we respond to your 
request;
    (4) Include copies of all relevant documents;
    (5) Provide your analysis of the issue(s), including citations to 
all relevant precedents (including adverse precedents); and
    (6) Suggest a proposed valuation method.
    (b) In response to your request, ONRR may:
    (1) Request that the Assistant Secretary for Policy, Management and 
Budget issue a determination;
    (2) Decide that ONRR will issue guidance; or
    (3) Inform you in writing that ONRR will not provide a 
determination or guidance. Situations in which ONRR typically will not 
provide any determination or guidance include, but are not limited to:
    (i) Requests for guidance on hypothetical situations; or
    (ii) Matters that are the subject of pending litigation or 
administrative appeals.
    (c)(1) A determination that the Assistant Secretary for Policy, 
Management and Budget signs is binding on both you and ONRR until the 
Assistant Secretary modifies or rescinds it.
    (2) After the Assistant Secretary issues a determination, you must 
make any adjustments in royalty payments that follow from the 
determination and, if you owe additional royalties, you must pay any 
additional royalties due, plus late payment interest calculated under 
Sec.  1218.202 of this chapter.
    (3) A determination that 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 that ONRR issues is not binding on ONRR, delegated 
States, or you with respect to the specific situation addressed in the 
guidance.
    (1) Guidance and ONRR's decision whether or not to issue guidance 
or to request an Assistant Secretary determination, or neither, under 
paragraph (b) of this section, are not appealable decisions or orders 
under 30 CFR part 1290.
    (2) If you receive an order requiring you to pay royalty on the 
same basis as the guidance, you may appeal that order under 30 CFR part 
1290.
    (e) ONRR or the Assistant Secretary may use any of the applicable 
criteria in this subpart to provide guidance or to make a 
determination.
    (f) A change in an applicable statute or regulation on which ONRR 
based any guidance, or the Assistant Secretary based any determination, 
takes precedence over the determination or guidance after the effective 
date of the statute or regulation, regardless of whether ONRR or the 
Assistant Secretary modifies or rescinds the guidance or determination.
    (g) ONRR may make requests and replies under this section available 
to the public, subject to the confidentiality requirements under Sec.  
1206.259.


Sec.  1206.259  Does ONRR protect information that I provide?

    (a) Certain information that you or your affiliate submit(s) to 
ONRR regarding royalties on coal, including deductions and allowances, 
may be exempt from disclosure.
    (b) To the extent that applicable laws and regulations permit, ONRR 
will keep confidential any data that 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

[[Page 43392]]

Freedom of Information Act regulations of the Department of the 
Interior at 43 CFR part 2.


Sec.  1206.260  What general transportation allowance requirements 
apply to me?

    (a)(1) ONRR will allow a deduction for the reasonable, actual costs 
to transport coal from the lease to the point off of the lease or mine 
as determined under Sec.  1206.261 or Sec.  1206.262, as applicable.
    (2) You do not need ONRR's approval before reporting a 
transportation allowance for costs incurred.
    (b) You may take a transportation allowance when:
    (1) You value coal under Sec.  1206.252;
    (2) You transport the coal from a Federal lease to a sales point, 
which is remote from both the lease and mine; or
    (3) You transport the coal from a Federal lease to a wash plant 
when that plant is remote from both the lease and mine and, if 
applicable, from the wash plant to a remote sales point.
    (c) You may not take an allowance for:
    (1) Transporting lease production that is not royalty-bearing;
    (2) In-mine movement of your coal; or
    (3) Costs to move a particular tonnage of production for which you 
did not incur those costs.
    (d) You may only claim a transportation allowance when you sell the 
coal and pay royalties.
    (e) You must allocate transportation allowances to the coal 
attributed to the lease from which it was extracted.
    (1) If you commingle coal produced from Federal and non-Federal 
leases, you may not disproportionately allocate transportation costs to 
Federal lease production. Your allocation must use the same proportion 
as the ratio of the tonnage from the Federal lease production to the 
tonnage from all production.
    (2) If you commingle coal produced from more than one Federal 
lease, you must allocate transportation costs to each Federal lease, as 
appropriate. Your allocation must use the same proportion as the ratio 
of the tonnage of each Federal lease production to the tonnage of all 
production.
    (3) For washed coal, you must allocate the total transportation 
allowance only to washed products.
    (4) For unwashed coal, you may take a transportation allowance for 
the total coal transported.
    (5)(i) You must report your transportation costs on Form ONRR-4430 
as clean coal short tons sold during the reporting period multiplied by 
the sum of the per-short-ton cost of transporting the raw tonnage to 
the wash plant and, if applicable, the per-short-ton cost of 
transporting the clean coal tons from the wash plant to a remote sales 
point.
    (ii) You must determine the cost per short ton of clean coal 
transported by dividing the total applicable transportation cost by the 
number of clean coal tons resulting from washing the raw coal 
transported.
    (f) You must express transportation allowances for coal as a 
dollar-value equivalent per short ton of coal transported. If you do 
not base your or your affiliate's payments for transportation under a 
transportation contract on a dollar-per-unit basis, you must convert 
whatever consideration that you or your affiliate paid to a dollar-
value equivalent.
    (g) ONRR may determine your transportation allowance under Sec.  
1206.254 because:
    (1) There is misconduct by or between the contracting parties;
    (2) ONRR determines that the consideration that you or your 
affiliate paid under an arm's-length transportation contract does not 
reflect the reasonable cost of the transportation because you breached 
your duty to market the coal for the mutual benefit of yourself and the 
lessor by transporting your coal at a cost that is unreasonably high. 
We may consider a transportation allowance unreasonably high if it is 
10 percent higher than the highest reasonable measures of 
transportation costs, including, but not limited to, transportation 
allowances reported to ONRR and the cost to transport coal through the 
same transportation system; or
    (3) ONRR cannot determine if you properly calculated a 
transportation allowance under Sec.  1206.261 or Sec.  1206.262 for any 
reason, including, but not limited to, your or your affiliate's failure 
to provide documents that ONRR requests under 30 CFR part 1212, subpart 
E.


Sec.  1206.261  How do I determine a transportation allowance if I have 
an arm's-length transportation contract or no written arm's-length 
contract?

    (a) If you or your affiliate incur(s) transportation costs under an 
arm's-length transportation contract, you may claim a transportation 
allowance for the reasonable, actual costs incurred for transporting 
the coal under that contract.
    (b) You must be able to demonstrate that your or your affiliate's 
contract is at arm's-length.
    (c) If you have no written contract for the arm's-length 
transportation of coal, then ONRR will determine your transportation 
allowance under Sec.  1206.254. You may not use this paragraph (c) if 
you or your affiliate perform(s) your own transportation.
    (1) You must propose to ONRR a method to determine the allowance 
using the procedures in Sec.  1206.258(a).
    (2) You may use that method to determine your allowance until ONRR 
issues a determination.


Sec.  1206.262  How do I determine a transportation allowance if I do 
not have an arm's-length transportation contract?

    (a) This section applies if you or your affiliate do(es) not have 
an arm's-length transportation contract, including situations where you 
or your affiliate provide your own transportation services. You must 
calculate your transportation allowance based on your or your 
affiliate's reasonable, actual costs for transportation during the 
reporting period using the procedures prescribed in this section.
    (b) Your or your affiliate's actual costs may include:
    (1) Capital costs and operating and maintenance expenses under 
paragraphs (d), (e), and (f) of this section.
    (2) Overhead under paragraph (g) of this section.
    (3) Depreciation under paragraph (h) of this section and a return 
on undepreciated capital investment under paragraph (i) of this 
section, or you may elect to use a cost equal to a return on the 
initial depreciable capital investment in the transportation system 
under paragraph (j) of this section. After you have elected to use 
either method for a transportation system, you may not later elect to 
change to the other alternative without ONRR's approval. If ONRR 
accepts your request to change methods, you may use your changed method 
beginning with the production month following the month when ONRR 
received your change request.
    (4) A return on the reasonable salvage value, under paragraph (i) 
of this section, after you have depreciated the transportation system 
to its reasonable salvage value.
    (c) You may not use any cost as a deduction that duplicates all or 
part of any other cost that you use under this section.
    (d) Allowable capital investment costs are generally those for 
depreciable fixed assets (including costs of delivery and installation 
of capital equipment), which are an integral part of the transportation 
system.
    (e) Allowable operating expenses include the following:
    (1) Operations supervision and engineering.
    (2) Operations labor.
    (3) Fuel.

[[Page 43393]]

    (4) Utilities.
    (5) Materials.
    (6) Ad valorem property taxes.
    (7) Rent.
    (8) Supplies.
    (9) Any other directly allocable and attributable operating 
expenses that you can document.
    (f) Allowable maintenance expenses include the following:
    (1) Maintenance of the transportation system.
    (2) Maintenance of equipment.
    (3) Maintenance labor.
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (g) Overhead, directly attributable and allocable to the operation 
and maintenance of the transportation system, is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (h)(1) To calculate depreciation, you may elect to use either a 
straight-line depreciation method based on the life of the 
transportation system or the life of the reserves that the 
transportation system services, or you may elect to use a unit-of-
production method. After you make an election, you may not change 
methods without ONRR's approval. If ONRR accepts your request to change 
methods, you may use your changed method beginning with the production 
month following the month when ONRR received your change request.
    (2) A change in ownership of a transportation system will not alter 
the depreciation schedule that the original transporter/lessee 
established for the purposes of the allowance calculation.
    (3) You may depreciate a transportation system only once with or 
without a change in ownership.
    (i)(1) To calculate a return on undepreciated capital investment, 
you must multiply the remaining undepreciated capital balance as of the 
beginning of the period for which you are calculating the 
transportation allowance by the rate of return provided in paragraph 
(k) of this section.
    (2) After you have depreciated a transportation system to its 
reasonable salvage value, you may continue to include in the allowance 
calculation a cost equal to the reasonable salvage value multiplied by 
a rate of return determined under paragraph (k) of this section.
    (j) As an alternative to using depreciation and a return on 
undepreciated capital investment, as provided under paragraph (b)(3) of 
this section, you may use as a cost an amount equal to the allowable 
initial capital investment in the transportation system multiplied by 
the rate of return determined under paragraph (k) of this section. You 
may not include depreciation in your allowance.
    (k) The rate of return is the industrial rate associated with 
Standard & Poor's BBB rating.
    (1) You must use the monthly average BBB rate that Standard & 
Poor's publishes for the first month for which the allowance is 
applicable.
    (2) You must re-determine the rate at the beginning of each 
subsequent calendar year.


Sec.  1206.263  What are my reporting requirements under an arm's-
length transportation contract?

    (a) You must use a separate entry on Form ONRR-4430 to notify ONRR 
of an allowance based on transportation costs that you or your 
affiliate incur(s).
    (b) ONRR may require you or your affiliate to submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents.
    (c) You can find recordkeeping requirements in parts 1207 and 1212 
of this chapter.


Sec.  1206.264  What are my reporting requirements under a non-arm's-
length transportation contract?

    (a) You must use a separate entry on Form ONRR-4430 to notify ONRR 
of an allowance based on non-arm's-length transportation costs you or 
your affiliate incur(s).
    (b)(1) For new non-arm's-length transportation facilities or 
arrangements, you must base your initial deduction on estimates of 
allowable transportation costs for the applicable period.
    (2) You must use your or your affiliate's most recently available 
operations data for the transportation system as your estimate, if 
available. If such data is not available, you must use estimates based 
on data for similar transportation systems.
    (3) Section 1206.266 applies when you amend your report based on 
the actual costs.
    (c) ONRR may require you or your affiliate to submit all data used 
to calculate the allowance deduction. You can find recordkeeping 
requirements in parts 1207 and 1212 of this chapter.


Sec.  1206.265  What interest and penalties apply if I improperly 
report a transportation allowance?

    (a)(1) If ONRR determines that you took an unauthorized 
transportation allowance, then you must pay any additional royalties 
due, plus late payment interest calculated under Sec.  1218.202 of this 
chapter.
    (2) If you understated your transportation allowance, you may be 
entitled to a credit without interest.
    (b) If you improperly net a transportation allowance against the 
sales value of the coal instead of reporting the allowance as a 
separate entry on Form ONRR-4430, ONRR may assess a civil penalty under 
30 CFR part 1241.


Sec.  1206.266  What reporting adjustments must I make for 
transportation allowances?

    (a) If your actual transportation allowance is less than the amount 
that you claimed on Form ONRR-4430 for each month during the allowance 
reporting period, you must pay additional royalties due, plus late 
payment interest calculated under Sec.  1218.202 of this chapter from 
the date when you took the deduction to the date when you repay the 
difference.
    (b) If the actual transportation allowance is greater than the 
amount that you claimed on Form ONRR-4430 for any month during the 
period reported on the allowance form, you are entitled to a credit 
without interest.


Sec.  1206.267  What general washing allowance requirements apply to 
me?

    (a)(1) If you determine the value of your coal under Sec.  
1206.252, you may take a washing allowance for the reasonable, actual 
costs to wash the coal. The allowance is a deduction when determining 
coal royalty value for the costs that you incur to wash coal.
    (2) You do not need ONRR's approval before reporting a washing 
allowance.
    (b) You may not:
    (1) Take an allowance for the costs of washing lease production 
that is not royalty bearing.
    (2) Disproportionately allocate washing costs to Federal leases. 
You must allocate washing costs to washed coal attributable to each 
Federal lease by multiplying the input ratio determined under Sec.  
1206.251(e)(2)(i) by the total allowable costs.
    (c)(1) You must express washing allowances for coal as a dollar-
value equivalent per short ton of coal washed.
    (2) If you do not base your or your affiliate's payments for 
washing under an arm's-length contract on a dollar-per-unit basis, you 
must convert whatever consideration that you or your affiliate paid to 
a dollar-value equivalent.
    (d) ONRR may determine your washing allowance under Sec.  1206.254 
because:
    (1) There is misconduct by or between the contracting parties;
    (2) ONRR determines that the consideration that you or your 
affiliate paid under an arm's-length washing

[[Page 43394]]

contract does not reflect the reasonable cost of the washing because 
you breached your duty to market the coal for the mutual benefit of 
yourself and the lessor by washing your coal at a cost that is 
unreasonably high. We may consider a washing allowance unreasonably 
high if it is 10 percent higher than the highest other reasonable 
measures of washing, including, but not limited to, washing allowances 
reported to ONRR and costs for coal washed in the same plant or other 
plants in the region; or
    (3) ONRR cannot determine if you properly calculated a washing 
allowance under Sec. Sec.  1206.267 through 1206.269 for any reason, 
including, but not limited to, your or your affiliate's failure to 
provide documents that ONRR requests under 30 CFR part 1212, subpart E.
    (e) You may only claim a washing allowance when you sell the washed 
coal and report and pay royalties.


Sec.  1206.268  How do I determine washing allowances if I have an 
arm's-length washing contract or no written arm's-length contract?

    (a) If you or your affiliate incur(s) washing costs under an arm's-
length washing contract, you may claim a washing allowance for the 
reasonable, actual costs incurred.
    (b) You must be able to demonstrate that your or your affiliate's 
contract is arm's-length.
    (c) If you have no written contract for the arm's-length washing of 
coal, then ONRR will determine your washing allowance under Sec.  
1206.254. You may not use this paragraph (c) if you or your affiliate 
perform(s) your own washing. If you or your affiliate perform(s) the 
washing, then
    (1) You must propose to ONRR a method to determine the allowance 
using the procedures in Sec.  1206.258(a).
    (2) You may use that method to determine your allowance until ONRR 
issues a determination.


Sec.  1206.269  How do I determine washing allowances if I do not have 
an arm's-length washing contract?

    (a) This section applies if you or your affiliate do(es) not have 
an arm's-length washing contract, including situations where you or 
your affiliate provides your own washing services. You must calculate 
your washing allowance based on your or your affiliate's reasonable, 
actual costs for washing during the reporting period using the 
procedures prescribed in this section.
    (b) Your or your affiliate's actual costs may include:
    (1) Capital costs and operating and maintenance expenses under 
paragraphs (d), (e), and (f) of this section.
    (2) Overhead under paragraph (g) of this section.
    (3) Depreciation under paragraph (h) of this section and a return 
on undepreciated capital investment under paragraph (i) of this 
section, or you may elect to use a cost equal to a return on the 
initial depreciable capital investment in the wash plant under 
paragraph (j) of this section. After you have elected to use either 
method for a wash plant, you may not later elect to change to the other 
alternative without ONRR's approval. If ONRR accepts your request to 
change methods, you may use your changed method beginning with the 
production month following the month when ONRR received your change 
request.
    (4) A return on the reasonable salvage value, under paragraph (i) 
of this section, after you have depreciated the wash plant to its 
reasonable salvage value.
    (c) You may not use any cost as a deduction that duplicates all or 
part of any other cost that you use under this section.
    (d) Allowable capital investment costs are generally those for 
depreciable fixed assets (including costs of delivery and installation 
of capital equipment), which are an integral part of the wash plant.
    (e) Allowable operating expenses include the following:
    (1) Operations supervision and engineering.
    (2) Operations labor.
    (3) Fuel.
    (4) Utilities.
    (5) Materials.
    (6) Ad valorem property taxes.
    (7) Rent.
    (8) Supplies.
    (9) Any other directly allocable and attributable operating 
expenses that you can document.
    (f) Allowable maintenance expenses include the following:
    (1) Maintenance of the wash plant.
    (2) Maintenance of equipment.
    (3) Maintenance labor.
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (g) Overhead, directly attributable and allocable to the operation 
and maintenance of the wash plant, is an allowable expense. State and 
Federal income taxes and severance taxes and other fees, including 
royalties, are not allowable expenses.
    (h)(1) To calculate depreciation, you may elect to use either a 
straight-line depreciation method based on the life of the wash plant 
or the life of the reserves that the wash plant services, or you may 
elect to use a unit-of-production method. After you make an election, 
you may not change methods without ONRR's approval. If ONRR accepts 
your request to change methods, you may use your changed method 
beginning with the production month following the month when ONRR 
received your change request.
    (2) A change in ownership of a wash plant will not alter the 
depreciation schedule that the original washer/lessee established for 
purposes of the allowance calculation.
    (3) With or without a change in ownership, you may depreciate a 
wash plant only once.
    (i)(1) To calculate a return on undepreciated capital investment, 
you must multiply the remaining undepreciated capital balance as of the 
beginning of the period for which you are calculating the washing 
allowance by the rate of return provided in paragraph (k) of this 
section.
    (2) After you have depreciated a wash plant to its reasonable 
salvage value, you may continue to include in the allowance calculation 
a cost equal to the salvage value multiplied by a rate of return 
determined under paragraph (k) of this section.
    (j) As an alternative to using depreciation and a return on 
undepreciated capital investment, as provided under paragraph (b)(3) of 
this section, you may use as a cost an amount equal to the allowable 
initial capital investment in the wash plant multiplied by the rate of 
return as determined under paragraph (k) of this section. You may not 
include depreciation in your allowance.
    (k) The rate of return is the industrial rate associated with 
Standard & Poor's BBB rating.
    (1) You must use the monthly average BBB rate that Standard & 
Poor's publishes for the first month for which the allowance is 
applicable.
    (2) You must re-determine the rate at the beginning of each 
subsequent calendar year.


Sec.  1206.270  What are my reporting requirements under an arm's-
length washing contract?

    (a) You must use a separate entry on Form ONRR-4430 to notify ONRR 
of an allowance based on washing costs that you or your affiliate 
incur(s).
    (b) ONRR may require you or your affiliate to submit arm's-length 
washing contracts, production agreements, operating agreements, and 
related documents.

[[Page 43395]]

    (c) You can find recordkeeping requirements in parts 1207 and 1212 
of this chapter.


Sec.  1206.271  What are my reporting requirements under a non-arm's-
length washing contract?

    (a) You must use a separate entry on Form ONRR-4430 to notify ONRR 
of an allowance based on non-arm's-length washing costs that you or 
your affiliate incur(s).
    (b)(1) For new non-arm's-length washing facilities or arrangements, 
you must base your initial deduction on estimates of allowable washing 
costs for the applicable period.
    (2) You must use your or your affiliate's most recently available 
operations data for the wash plant as your estimate, if available. If 
such data is not available, you must use estimates based on data for 
similar wash plants.
    (3) Section 1206.273 applies when you amend your report based on 
the actual costs.
    (c) ONRR may require you or your affiliate to submit all data used 
to calculate the allowance deduction. You can find recordkeeping 
requirements in parts 1207 and 1212 of this chapter.


Sec.  1206.272  What interest and penalties apply if I improperly 
report a washing allowance?

    (a)(1) If ONRR determines that you took an unauthorized washing 
allowance, then you must pay any additional royalties due, plus late 
payment interest calculated under Sec.  1218.202 of this chapter.
    (2) If you understated your washing allowance, you may be entitled 
to a credit without interest.
    (b) If you improperly net a washing allowance against the sales 
value of the coal instead of reporting the allowance as a separate 
entry on Form ONRR-4430, ONRR may assess a civil penalty under 30 CFR 
part 1241.


Sec.  1206.273  What reporting adjustments must I make for washing 
allowances?

    (a) If your actual washing allowance is less than the amount that 
you claimed on Form ONRR-4430 for each month during the allowance 
reporting period, you must pay additional royalties due, plus late 
payment interest calculated under Sec.  1218.202 of this chapter from 
the date when you took the deduction to the date when you repay the 
difference.
    (b) If the actual washing allowance is greater than the amount that 
you claimed on Form ONRR-4430 for any month during the period reported 
on the allowance form, you are entitled to a credit without interest.

0
9. Revise subpart J to read as follows:
Subpart J--Indian Coal
1206.450 What is the purpose and scope of this subpart?
1206.451 How do I determine royalty quantity and quality?
1206.452 How do I calculate royalty value for coal that I or my 
affiliate sell(s) under an arm's-length or non-arm's-length 
contract?
1206.453 How will ONRR determine if my royalty payments are correct?
1206.454 How will ONRR determine the value of my coal for royalty 
purposes?
1206.455 What records must I keep in order to support my 
calculations of royalty under this subpart?
1206.456 What are my responsibilities to place production into 
marketable condition and to market production?
1206.457 When is an ONRR audit, review, reconciliation, monitoring, 
or other like process considered final?
1206.458 How do I request a valuation determination?
1206.459 Does ONRR protect information that I provide?
1206.460 What general transportation allowance requirements apply to 
me?
1206.461 How do I determine a transportation allowance if I have an 
arm's-length transportation contract or no written arm's-length 
contract?
1206.462 How do I determine a transportation allowance if I do not 
have an arm's-length transportation contract?
1206.463 What are my reporting requirements under an arm's-length 
transportation contract?
1206.464 What are my reporting requirements under a non-arm's-length 
transportation contract or no written arm's-length contract?
1206.465 What interest and penalties apply if I improperly report a 
transportation allowance?
1206.466 What reporting adjustments must I make for transportation 
allowances?
1206.467 What general washing allowance requirements apply to me?
1206.468 How do I determine washing allowances if I have an arm's-
length washing contract or no written arm's-length contract?
1206.469 How do I determine washing allowances if I do not have an 
arm's-length washing contract?
1206.470 What are my reporting requirements under an arm's-length 
washing contract?
1206.471 What are my reporting requirements under a non-arm's-length 
washing contract or no written arm's-length contract?
1206.472 What interest and penalties apply if I improperly report a 
washing allowance?
1206.473 What reporting adjustments must I make for washing 
allowances?

Subpart J--Indian Coal


Sec.  1206.450  What is the purpose and scope of this subpart?

    (a) This subpart applies to all coal produced from Indian Tribal 
coal leases and coal leases on land held by individual Indian mineral 
owners. It explains how you, as the lessee, must calculate the value of 
production for royalty purposes consistent with the mineral leasing 
laws, other applicable laws, and lease terms (except leases on the 
Osage Indian Reservation, Osage County, Oklahoma).
    (b) The terms ``you'' and ``your'' in this subpart refer to the 
lessee.
    (c) If the regulations in this subpart are inconsistent with a(an): 
Federal statute; settlement agreement between the United States and a 
lessee resulting from administrative or judicial litigation; written 
agreement between the lessee and ONRR's 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 express provision of a coal lease subject to this subpart, then the 
statute, settlement agreement, written agreement, or lease provision 
will govern to the extent of the inconsistency.
    (d) ONRR may audit and order you to adjust all royalty payments.
    (e) The regulations in this subpart, intended to ensure that the 
trust responsibilities of the United States with respect to the 
administration of Indian coal leases, are discharged under the 
requirements of the governing mineral leasing laws, treaties, and lease 
terms.


Sec.  1206.451  How do I determine royalty quantity and quality?

    (a) You must calculate royalties based on the quantity and quality 
of coal at the royalty measurement point that ONRR and BLM jointly 
determine.
    (b) You must measure coal in short tons using the methods that BLM 
prescribes for Indian coal leases. You must report coal quantity on 
appropriate forms required in 30 CFR part 1210.
    (c)(1) You are not required to pay royalties on coal that you 
produce and add to stockpiles or inventory until you use, sell, or 
otherwise finally dispose of such coal.
    (2) ONRR may request that BLM require you to increase your lease 
bond if BLM determines that stockpiles or inventory are excessive such 
that they increase the risk of resource degradation.
    (d) You must pay royalty at the rate specified in your lease at the 
time when you use, sell, or otherwise finally dispose of the coal.
    (e) You must allocate washed coal by attributing the washed coal to 
the leases from which it was extracted.
    (1) If the wash plant washes coal from only one lease, the quantity 
of washed

[[Page 43396]]

coal allocable to the lease is the total output of washed coal from the 
plant.
    (2) If the wash plant washes coal from more than one lease, you 
must determine the tonnage of washed coal attributable to each lease 
by:
    (i) First, calculating the input ratio of washed coal allocable to 
each lease by dividing the tonnage of coal input to the wash plant from 
each lease by the total tonnage of coal input to the wash plant from 
all leases.
    (ii) Second, multiplying the input ratio derived under paragraph 
(e)(2)(i) of this section by the tonnage of total output of washed coal 
from the plant.


Sec.  1206.452  How do I calculate royalty value for coal that I or my 
affiliate sell(s) under an arm's-length or non-arm's-length contract?

    (a) The value of coal under this section for royalty purposes is 
the gross proceeds accruing to you or your affiliate under the first 
arm's-length contract less an applicable transportation allowance 
determined under Sec. Sec.  1206.460 through 1206.462 and washing 
allowance under Sec. Sec.  1206.467 through 1206.469. You must use this 
paragraph (a) to value coal when:
    (1) You sell under an arm's-length contract; or
    (2) You sell or transfer to your affiliate or another person under 
a non-arm's-length contract, and that affiliate or person, or another 
affiliate of either of them, then sells the coal under an arm's-length 
contract.
    (b) If you have no contract for the sale of coal subject to this 
section because you or your affiliate used the coal in a power plant 
that you or your affiliate own(s) for the generation and sale of 
electricity, one of the following applies:
    (1) You or your affiliate sell(s) the electricity, then the value 
of the coal subject to this section, for royalty purposes, is the gross 
proceeds accruing to you for the power plant's arm's-length sales of 
the electricity less applicable transportation and washing deductions 
determined under Sec. Sec.  1206.460 through 1206.462 and Sec. Sec.  
1206.467 through 1206.469 and, if applicable, transmission and 
generation deductions determined under Sec. Sec.  1206.353 and 
1206.352.
    (2) You or your affiliate do(es) not sell the electricity at arm's-
length (for example you or your affiliate deliver(s) the electricity 
directly to the grid), then ONRR will determine the value of the coal 
under Sec.  1206.454.
    (i) You must propose to ONRR a method to determine the value using 
the procedures in Sec.  1206.458(a).
    (ii) You may use that method to determine value, for royalty 
purposes, until ONRR issues a determination.
    (iii) After ONRR issues a determination, you must make the 
adjustments under Sec.  1206.453(a)(2).
    (c) If you are a coal cooperative, or a member of a coal 
cooperative, one of the following applies:
    (1) You sell or transfer coal to another member of the coal 
cooperative, and that member of the coal cooperative then sells the 
coal under an arm's-length contract, then you must value the coal under 
paragraph (a) of this section.
    (2) You sell or transfer coal to another member of the coal 
cooperative, and you, the coal cooperative, or another member of the 
coal cooperative use the coal in a power plant for the generation and 
sale of electricity, then you must value the coal under paragraph (b) 
of this section.
    (d) If you are entitled to take a washing allowance and 
transportation allowance for royalty purposes under this section, under 
no circumstances may the washing allowance plus the transportation 
allowance reduce the royalty value of the coal to zero.
    (e) The values in this section do not apply if ONRR decides to 
value your coal under Sec.  1206.454.


Sec.  1206.453  How will ONRR determine if my royalty payments are 
correct?

    (a)(1) ONRR may monitor, review, and audit the royalties that you 
report. If ONRR determines that your reported value is inconsistent 
with the requirements of this subpart, ONRR will direct you to use a 
different measure of royalty value, or decide your value, under Sec.  
1206.454.
    (2) If ONRR directs you to use a different royalty value, you must 
either pay any underpaid royalties plus late payment interest 
calculated under Sec.  1218.202 of this chapter or report a credit for, 
or request a refund of, any overpaid royalties.
    (b) When the provisions in this subpart refer to gross proceeds, in 
conducting reviews and audits, ONRR will examine if your or your 
affiliate's contract reflects the total consideration actually 
transferred, either directly or indirectly, from the buyer to you or 
your affiliate for the coal. If ONRR determines that a contract does 
not reflect the total consideration, ONRR may decide your value under 
Sec.  1206.454.
    (c) ONRR may decide to value your coal under Sec.  1206.454, if 
ONRR determines that the gross proceeds accruing to you or your 
affiliate under a contract do not reflect reasonable consideration 
because:
    (1) There is misconduct by or between the contracting parties;
    (2) You breached your duty to market the coal for the mutual 
benefit of yourself and the lessor by selling your coal at a value that 
is unreasonably low. ONRR may consider a sales price unreasonably low, 
if it is 10 percent less than the lowest other reasonable measures of 
market price, including, but not limited to, prices reported to ONRR 
for like-quality coal; or
    (3) ONRR cannot determine if you properly valued your coal under 
Sec.  1206.452 for any reason, including, but not limited to, your or 
your affiliate's failure to provide documents to ONRR under 30 CFR part 
1212, subpart E.
    (d) You have the burden of demonstrating that your or your 
affiliate's contract is arm's-length.
    (e) ONRR may require you to certify that the provisions in your or 
your affiliate's contract include(s) all of the consideration that the 
buyer paid to you or your affiliate, either directly or indirectly, for 
the coal.
    (f)(1) Absent contract revision or amendment, if you or your 
affiliate fail(s) to take proper or timely action to receive prices or 
benefits to which you or your affiliate are entitled, you must pay 
royalty based upon that obtainable price or benefit.
    (2) If you or your affiliate apply in a timely manner 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 in a timely manner, for a quantity of coal.
    (g)(1) You or your affiliate must make all contracts, contract 
revisions, or amendments in writing, and all parties to the contract 
must sign the contract, contract revisions, or amendments.
    (2) If you or your affiliate fail(s) to comply with paragraph 
(g)(1) of this section, ONRR may decide to value your coal under Sec.  
1206.454.
    (3) This provision applies notwithstanding any other provisions in 
this title 30 to the contrary.


Sec.  1206.454  How will ONRR determine the value of my coal for 
royalty purposes?

    If ONRR decides to value your coal for royalty purposes under Sec.  
1206.454, or

[[Page 43397]]

any other provision in this subpart, then ONRR will determine value by 
considering any information that we deem relevant, which may include, 
but is not limited to:
    (a) The value of like-quality coal from the same mine, nearby 
mines, same region, other regions, or washed in the same or nearby wash 
plant.
    (b) Public sources of price or market information that ONRR deems 
reliable, including, but not limited to, the price of electricity.
    (c) Information available to ONRR and information reported to us, 
including but not limited to, on Form ONRR-4430.
    (d) Costs of transportation or washing, if ONRR determines they are 
applicable.
    (e) Any other information that ONRR deems to be relevant regarding 
the particular lease operation or the salability of the coal.


Sec.  1206.455  What records must I keep in order to support my 
calculations of royalty under this subpart?

    If you value your coal under this subpart, you must retain all data 
relevant to the determination of the royalty that you paid. You can 
find recordkeeping requirements in parts 1207 and 1212 of this chapter.
    (a) You must show:
    (1) How you calculated the royalty value, including all allowable 
deductions; and
    (2) How you complied with this subpart.
    (b) Upon request, you must submit all data to ONRR, the 
representative of the Indian lessor, the Inspector General of the 
Department of the Interior, or other persons authorized to receive such 
information. Such data may include arm's-length sales and sales 
quantity data for like-quality coal that you or your affiliate sold, 
purchased, or otherwise obtained from the same mine, nearby mines, same 
region, or other regions. You must comply with any such requirement 
within the time that ONRR specifies.


Sec.  1206.456  What are my responsibilities to place production into 
marketable condition and to market production?

    (a) You must place coal in marketable condition and market the coal 
for the mutual benefit of the lessee and the lessor at no cost to the 
Indian lessor.
    (b) If you use gross proceeds under an arm's-length contract to 
determine royalty, you must increase those gross proceeds to the extent 
that the purchaser, or any other person, provides certain services that 
you normally are responsible to perform in order to place the coal in 
marketable condition or to market the coal.


Sec.  1206.457  When is an ONRR audit, review, reconciliation, 
monitoring, or other like process considered final?

    Notwithstanding any provision in these regulations to the contrary, 
ONRR will not consider any audit, review, reconciliation, monitoring, 
or other like process that results in ONRR re-determining royalty due, 
under this subpart, final or binding as against the Federal government 
or its beneficiaries unless ONRR chooses to, in writing, formally close 
the audit period.


Sec.  1206.458  How do I request a valuation determination?

    (a) You may request a valuation determination from ONRR regarding 
any coal produced. Your request must:
    (1) Be in writing;
    (2) Identify specifically all leases involved, all interest owners 
of those leases, and the operator(s) for those leases;
    (3) Completely explain all relevant facts. You must inform ONRR of 
any changes to relevant facts that occur before we respond to your 
request;
    (4) Include copies of all relevant documents;
    (5) Provide your analysis of the issue(s), including citations to 
all relevant precedents (including adverse precedents); and
    (6) Suggest a proposed valuation method.
    (b) In response to your request, ONRR may:
    (1) Request that the Assistant Secretary for Policy, Management and 
Budget issue a determination;
    (2) Decide that ONRR will issue guidance; or
    (3) Inform you in writing that ONRR will not provide a 
determination or guidance. Situations in which ONRR typically will not 
provide any determination or guidance include, but are not limited to:
    (i) Requests for guidance on hypothetical situations; or
    (ii) Matters that are the subject of pending litigation or 
administrative appeals.
    (c)(1) A determination that the Assistant Secretary for Policy, 
Management and Budget signs is binding on both you and ONRR until the 
Assistant Secretary modifies or rescinds it.
    (2) After the Assistant Secretary issues a determination, you must 
make any adjustments in royalty payments that follow from the 
determination and, if you owe additional royalties, you must pay any 
additional royalties due, plus late payment interest calculated under 
Sec.  1218.202 of this chapter.
    (3) A determination that 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 that ONRR issues is not binding on ONRR, Tribes, 
individual Indian mineral owners, or you with respect to the specific 
situation addressed in the guidance.
    (1) Guidance and ONRR's decision whether or not to issue guidance 
or to request an Assistant Secretary determination, or neither, under 
paragraph (b) of this section, are not appealable decisions or orders 
under 30 CFR part 1290.
    (2) If you receive an order requiring you to pay royalty on the 
same basis as the guidance, you may appeal that order under 30 CFR part 
1290.
    (e) ONRR or the Assistant Secretary may use any of the applicable 
criteria in this subpart to provide guidance or to make a 
determination.
    (f) A change in an applicable statute or regulation on which ONRR 
based any guidance, or the Assistant Secretary based any determination, 
takes precedence over the determination or guidance after the effective 
date of the statute or regulation, regardless of whether ONRR or the 
Assistant Secretary modifies or rescinds the guidance or determination.
    (g) ONRR may make requests and replies under this section available 
to the public, subject to the confidentiality requirements under Sec.  
1206.459.


Sec.  1206.459  Does ONRR protect information that I provide?

    (a) Certain information that you or your affiliate submit(s) to 
ONRR regarding royalties on coal, including deductions and allowances, 
may be exempt from disclosure.
    (b) To the extent that applicable laws and regulations permit, ONRR 
will keep confidential any data that 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.


Sec.  1206.460  What general transportation allowance requirements 
apply to me?

    (a)(1) ONRR will allow a deduction for the reasonable, actual costs 
to transport coal from the lease to the point off of the lease or mine 
as determined under Sec.  1206.461 or Sec.  1206.462, as applicable.
    (2) Before you may take any transportation allowance, you must 
submit a completed page 1 of the Coal Transportation Allowance Report 
(Form ONRR-4293), under Sec. Sec.  1206.463 and

[[Page 43398]]

1206.464. You may claim a transportation allowance retroactively for a 
period of not more than three months prior to the first day of the 
month when ONRR receives your Form ONRR-4293.
    (3) You may not use a transportation allowance that was in effect 
before January 1, 2017. You must use the provisions of this subpart to 
determine your transportation allowance.
    (b) You may take a transportation allowance when:
    (1) You value coal under Sec.  1206.452;
    (2) You transport the coal from an Indian lease to a sales point 
that is remote from both the lease and mine; or
    (3) You transport the coal from an Indian lease to a wash plant 
when that plant is remote from both the lease and mine and, if 
applicable, from the wash plant to a remote sales point.
    (c) You may not take an allowance for:
    (1) Transporting lease production that is not royalty-bearing;
    (2) In-mine movement of your coal; or
    (3) Costs to move a particular tonnage of production for which you 
did not incur those costs.
    (d) You may only claim a transportation allowance when you sell the 
coal and pay royalties.
    (e) You must allocate transportation allowances to the coal 
attributed to the lease from which it was extracted.
    (1) If you commingle coal produced from Indian and non-Indian 
leases, you may not disproportionately allocate transportation costs to 
Indian lease production. Your allocation must use the same proportion 
as the ratio of the tonnage from the Indian lease production to the 
tonnage from all production.
    (2) If you commingle coal produced from more than one Indian lease, 
you must allocate transportation costs to each Indian lease, as 
appropriate. Your allocation must use the same proportion as the ratio 
of the tonnage of each Indian lease's production to the tonnage of all 
production.
    (3) For washed coal, you must allocate the total transportation 
allowance only to washed products.
    (4) For unwashed coal, you may take a transportation allowance for 
the total coal transported.
    (5)(i) You must report your transportation costs on Form ONRR-4430 
as clean coal short tons sold during the reporting period multiplied by 
the sum of the per short-ton cost of transporting the raw tonnage to 
the wash plant and, if applicable, the per short-ton cost of 
transporting the clean coal tons from the wash plant to a remote sales 
point.
    (ii) You must determine the cost per short ton of clean coal 
transported by dividing the total applicable transportation cost by the 
number of clean coal tons resulting from washing the raw coal 
transported.
    (f) You must express transportation allowances for coal as a 
dollar-value equivalent per short ton of coal transported. If you do 
not base your or your affiliate's payments for transportation under a 
transportation contract on a dollar-per-unit basis, you must convert 
whatever consideration that you or your affiliate paid into a dollar-
value equivalent.
    (g) ONRR may determine your transportation allowance under Sec.  
1206.454 because:
    (1) There is misconduct by or between the contracting parties;
    (2) ONRR determines that the consideration that you or your 
affiliate paid under an arm's-length transportation contract does not 
reflect the reasonable cost of the transportation because you breached 
your duty to market the coal for the mutual benefit of yourself and the 
lessor by transporting your coal at a cost that is unreasonably high. 
We may consider a transportation allowance unreasonably high if it is 
10 percent higher than the highest reasonable measures of 
transportation costs, including, but not limited to, transportation 
allowances reported to ONRR and the cost to transport coal through the 
same transportation system; or
    (3) ONRR cannot determine if you properly calculated a 
transportation allowance under Sec.  1206.461 or Sec.  1206.462 for any 
reason, including, but not limited to, your or your affiliate's failure 
to provide documents that ONRR requests under 30 CFR part 1212, subpart 
E.


Sec.  1206.461  How do I determine a transportation allowance if I have 
an arm's-length transportation contract or no written arm's-length 
contract?

    (a) If you or your affiliate incur(s) transportation costs under an 
arm's-length transportation contract, you may claim a transportation 
allowance for the reasonable, actual costs incurred for transporting 
the coal under that contract.
    (b) You must be able to demonstrate that your or your affiliate's 
contract is at arm's-length.
    (c) If you have no written contract for the arm's-length 
transportation of coal, then ONRR will determine your transportation 
allowance under Sec.  1206.454. You may not use this paragraph (c) if 
you or your affiliate perform(s) your own transportation.
    (1) You must propose to ONRR a method to determine the allowance 
using the procedures in Sec.  1206.458(a).
    (2) You may use that method to determine your allowance until ONRR 
issues a determination.


Sec.  1206.462  How do I determine a transportation allowance if I do 
not have an arm's-length transportation contract?

    (a) This section applies if you or your affiliate do(es) not have 
an arm's-length transportation contract, including situations where you 
or your affiliate provide your own transportation services. Calculate 
your transportation allowance based on your or your affiliate's 
reasonable, actual costs for transportation during the reporting period 
using the procedures prescribed in this section.
    (b) Your or your affiliate's actual costs may include:
    (1) Capital costs and operating and maintenance expenses under 
paragraphs (d), (e), and (f) of this section.
    (2) Overhead under paragraph (g) of this section.
    (3) Depreciation under paragraph (h) of this section and a return 
on undepreciated capital investment under paragraph (i) of this 
section, or you may elect to use a cost equal to a return on the 
initial depreciable capital investment in the transportation system 
under paragraph (j) of this section. After you have elected to use 
either method for a transportation system, you may not later elect to 
change to the other alternative without ONRR's approval. If ONRR 
accepts your request to change methods, you may use your changed method 
beginning with the production month following the month when ONRR 
received your change request.
    (c) You may not use any cost as a deduction that duplicates all or 
part of any other cost that you use under this section.
    (d) Allowable capital investment costs are generally those for 
depreciable fixed assets (including costs of delivery and installation 
of capital equipment), which are an integral part of the transportation 
system.
    (e) Allowable operating expenses include the following:
    (1) Operations supervision and engineering.
    (2) Operations labor.
    (3) Fuel.
    (4) Utilities.
    (5) Materials.
    (6) Ad valorem property taxes.
    (7) Rent.
    (8) Supplies.
    (9) Any other directly allocable and attributable operating expense 
that you can document.
    (f) Allowable maintenance expenses include the following:
    (1) Maintenance of the transportation system.

[[Page 43399]]

    (2) Maintenance of equipment.
    (3) Maintenance labor.
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (g) Overhead, directly attributable and allocable to the operation 
and maintenance of the transportation system, is an allowable expense. 
State and Federal income taxes and Indian Tribal severance taxes and 
other fees, including royalties, are not allowable expenses.
    (h)(1) To calculate depreciation, you may elect to use either a 
straight-line depreciation method based on the life of the 
transportation system or the life of the reserves that the 
transportation system services, or you may elect to use a unit-of-
production method. After you make an election, you may not change 
methods without ONRR's approval. If ONRR accepts your request to change 
methods, you may use your changed method beginning with the production 
month following the month when ONRR received your change request.
    (2) A change in ownership of a transportation system will not alter 
the depreciation schedule that the original transporter/lessee 
established for the purposes of the allowance calculation.
    (3) You may depreciate a transportation system only once with or 
without a change in ownership.
    (i) To calculate a return on undepreciated capital investment, 
multiply the remaining undepreciated capital balance as of the 
beginning of the period for which you are calculating the 
transportation allowance by the rate of return provided in paragraph 
(k) of this section.
    (j) As an alternative to using depreciation and a return on 
undepreciated capital investment, as provided under paragraph (b)(3) of 
this section, you may use as a cost an amount equal to the allowable 
initial capital investment in the transportation system multiplied by 
the rate of return determined under paragraph (k) of this section. You 
may not include depreciation in your allowance.
    (k) The rate of return is the industrial rate associated with 
Standard & Poor's BBB rating.
    (1) You must use the monthly average BBB rate that Standard & 
Poor's publishes for the first month for which the allowance is 
applicable.
    (2) You must re-determine the rate at the beginning of each 
subsequent calendar year.


Sec.  1206.463  What are my reporting requirements under an arm's-
length transportation contract?

    (a) You must use a separate entry on Form ONRR-4430 to notify ONRR 
of an allowance based on transportation costs you or your affiliate 
incur(s).
    (b) ONRR may require you or your affiliate to submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents.
    (c) You can find recordkeeping requirements in parts 1207 and 1212 
of this chapter.
    (d)(1) You must submit page 1 of the initial Form ONRR-4293 prior 
to, or at the same time as, you report the transportation allowance 
determined under an arm's-length contract on Form ONRR-4430.
    (2) The initial Form ONRR-4293 is effective beginning with the 
production month when you are first authorized to deduct a 
transportation allowance and continues until the end of the calendar 
year, or until the termination, modification, or amendment of the 
applicable contract or rate, whichever is earlier.
    (3) After the initial period when ONRR first authorized you to 
deduct a transportation allowance and for succeeding periods, you must 
submit the entire Form ONRR-4293 by the earlier of the following:
    (i) Within three months after the end of the calendar year
    (ii) After the termination, modification, or amendment of the 
applicable contract or rate
    (4) You may request to use an allowance for a longer period than 
that required under paragraph (d)(2) of this section.
    (i) You may use that allowance beginning with the production month 
following the month when ONRR received your request to use the 
allowance for a longer period until ONRR decides whether to approve the 
longer period.
    (ii) ONRR's decision whether or not to approve a longer period is 
not appealable under 30 CFR part 1290.
    (iii) If ONRR does not approve the longer period, you must adjust 
your transportation allowance under Sec.  1206.466.


Sec.  1206.464  What are my reporting requirements under a non-arm's-
length transportation contract or no written arm's-length contract?

    (a) You must use a separate entry on Form ONRR-4430 to notify ONRR 
of an allowance based on non-arm's-length transportation costs that you 
or your affiliate incur(s).
    (b) ONRR may require you or your affiliate to submit all data used 
to calculate the allowance deduction. You can find recordkeeping 
requirements in parts 1207 and 1212 of this chapter.
    (c)(1) You must submit an initial Form ONRR-4293 prior to, or at 
the same time as, the transportation allowance determined under a non-
arm's-length contract or no written arm's-length contract situation 
that you report on Form ONRR-4430. If ONRR receives a Form ONRR-4293 by 
the end of the month when the Form ONRR-4430 is due, ONRR will consider 
the form to be received in a timely manner. You may base the initial 
form on estimated costs.
    (2) The initial Form ONRR-4293 is effective beginning with the 
production month when you are first authorized to deduct a 
transportation allowance and continues until the end of the calendar 
year or termination, modification, or amendment of the applicable 
contract or rate, whichever is earlier.
    (3)(i) At the end of the calendar year for which you submitted a 
Form ONRR-4293 based on estimates, you must submit another, completed 
Form ONRR-4293 containing the actual costs for that calendar year.
    (ii) If the transportation continues, you must include on Form 
ONRR-4293 your estimated costs for the next calendar year.
    (A) You must base the estimated transportation allowance on the 
actual costs for the previous reporting period plus or minus any 
adjustments based on your knowledge of decreases or increases that will 
affect the allowance.
    (B) ONRR must receive Form ONRR-4293 within three months after the 
end of the previous calendar year.
    (d)(1) For new non-arm's-length transportation facilities or 
arrangements, on your initial ONRR-4293 form, you must include 
estimates of the allowable transportation costs for the applicable 
period.
    (2) You must use your or your affiliate's most recently available 
operations data for the transportation system as your estimate, if 
available. If such data is not available, you must use estimates based 
on data for similar transportation systems.
    (e) Upon ONRR's request, you must submit all data used to prepare 
your ONRR-4293 form. You must provide the data within a reasonable 
period of time, as ONRR determines.
    (f) Section 1206.466 applies when you amend your Form ONRR-4293 
based on the actual costs.


Sec.  1206.465  What interest and penalties apply if I improperly 
report a transportation allowance?

    (a)(1) If ONRR determines that you took an unauthorized 
transportation allowance, then you must pay any additional royalties 
due, plus late

[[Page 43400]]

payment interest calculated under Sec.  1218.202 of this chapter.
    (2) If you understated your transportation allowance, you may be 
entitled to a credit without interest.
    (b) If you improperly net a transportation allowance against the 
sales value of the coal instead of reporting the allowance as a 
separate entry on Form ONRR-4430, ONRR may assess a civil penalty under 
30 CFR part 1241.


Sec.  1206.466  What reporting adjustments must I make for 
transportation allowances?

    (a) If your actual transportation allowance is less than the amount 
that you claimed on Form ONRR-4430 for each month during the allowance 
reporting period, you must pay additional royalties due, plus late 
payment interest calculated under Sec.  1218.202 of this chapter from 
the date when you took the deduction to the date when you repay the 
difference.
    (b) If the actual transportation allowance is greater than the 
amount that you claimed on Form ONRR-4430 for any month during the 
period reported on the allowance form, you are entitled to a credit 
without interest.


Sec.  1206.467  What general washing allowance requirements apply to 
me?

    (a)(1) If you determine the value of your coal under Sec.  
1206.452, you may take a washing allowance for the reasonable, actual 
costs to wash coal. The allowance is a deduction when determining coal 
royalty value for the costs that you incur to wash coal.
    (2) Before you may take any deduction, you must submit a completed 
page 1 of the Coal Washing Allowance Report (Form ONRR-4292), under 
Sec. Sec.  1206.470 and 1206.471. You may claim a washing allowance 
retroactively for a period of not more than three months prior to the 
first day of the month when you have filed Form ONRR-4292 with ONRR.
    (3) You may not use a washing allowance that was in effect before 
January 1, 2017. You must use the provisions of this subpart to 
determine your washing allowance.
    (b) You may not:
    (1) Take an allowance for the costs of washing lease production 
that is not royalty bearing.
    (2) Disproportionately allocate washing costs to Indian leases. You 
must allocate washing costs to washed coal attributable to each Indian 
lease by multiplying the input ratio determined under Sec.  
1206.451(e)(2)(i) by the total allowable costs.
    (c)(1) You must express washing allowances for coal as a dollar-
value equivalent per short ton of coal washed.
    (2) If you do not base your or your affiliate's payments for 
washing under an arm's-length contract on a dollar-per-unit basis, you 
must convert whatever consideration that you or your affiliate paid 
into a dollar-value equivalent.
    (d) ONRR may determine your washing allowance under Sec.  1206.454 
because:
    (1) There is misconduct by or between the contracting parties;
    (2) ONRR determines that the consideration that you or your 
affiliate paid under an arm's-length washing contract does not reflect 
the reasonable cost of the washing because you breached your duty to 
market the coal for the mutual benefit of yourself and the lessor by 
washing your coal at a cost that is unreasonably high. We may consider 
a washing allowance to be unreasonably high if it is 10 percent higher 
than the highest other reasonable measures of washing, including, but 
not limited to, washing allowances reported to ONRR and costs for coal 
washed in the same plant or other plants in the region
    (3) ONRR cannot determine if you properly calculated a washing 
allowance under Sec. Sec.  1206.467 through 1206.469 for any reason, 
including, but not limited to, your or your affiliate's failure to 
provide documents that ONRR requests under 30 CFR part 1212, subpart E.
    (e) You may only claim a washing allowance if you sell the washed 
coal and report and pay royalties.


Sec.  1206.468  How do I determine washing allowances if I have an 
arm's-length washing contract or no written arm's-length contract?

    (a) If you or your affiliate incur(s) washing costs under an arm's-
length washing contract, you may claim a washing allowance for the 
reasonable, actual costs incurred.
    (b) You must be able to demonstrate that your or your affiliate's 
contract is arm's-length.
    (c) If you have no contract for the washing of coal, then ONRR will 
determine your transportation allowance under Sec.  1206.454. You may 
not use this paragraph (c), if you or your affiliate perform(s) your 
own washing. If you or your affiliate perform(s) the washing, then:
    (1) You must propose to ONRR a method to determine the allowance 
using the procedures in Sec.  1206.458(a).
    (2) You may use that method to determine your allowance until ONRR 
issues a determination.


Sec.  1206.469  How do I determine washing allowances if I do not have 
an non-arm's-length washing contract?

    (a) This section applies if you or your affiliate do(es) not have 
an arm's-length washing contract, including situations where you or 
your affiliate provides your own washing services. Calculate your 
washing allowance based on your or your affiliate's reasonable, actual 
costs for washing during the reporting period using the procedures 
prescribed in this section.
    (b) Your or your affiliate's actual costs may include:
    (1) Capital costs and operating and maintenance expenses under 
paragraphs (d), (e), and (f) of this section.
    (2) Overhead under paragraph (g) of this section.
    (3) Depreciation under paragraph (h) of this section and a return 
on undepreciated capital investment under paragraph (i) of this 
section, or a cost equal to a return on the initial depreciable capital 
investment in the wash plant under paragraph (j) of this section. After 
you have elected to use either method for a wash plant, you may not 
later elect to change to the other alternative without ONRR's approval. 
If ONRR accepts your request to change methods, you may use your 
changed method beginning with the production month following the month 
when ONRR received your change request.
    (c) You may not use any cost as a deduction that duplicates all or 
part of any other cost that you use under this section.
    (d) Allowable capital investment costs are generally those for 
depreciable fixed assets (including costs of delivery and installation 
of capital equipment), which are an integral part of the wash plant.
    (e) Allowable operating expenses include the following:
    (1) Operations supervision and engineering.
    (2) Operations labor.
    (3) Fuel.
    (4) Utilities.
    (5) Materials.
    (6) Ad valorem property taxes.
    (7) Rent.
    (8) Supplies.
    (9) Any other directly allocable and attributable operating 
expenses that you can document.
    (f) Allowable maintenance expenses include the following:
    (1) Maintenance of the wash plant.
    (2) Maintenance of equipment.
    (3) Maintenance labor.
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (g) Overhead, directly attributable and allocable to the operation 
and

[[Page 43401]]

maintenance of the wash plant is an allowable expense. State and 
Federal income taxes and Indian Tribal severance taxes and other fees, 
including royalties, are not allowable expenses.
    (h)(1) To calculate depreciation, you may elect to use either a 
straight-line depreciation method based on the life of the wash plant 
or the life of the reserves that the wash plant services, or you may 
elect to use a unit-of-production method. After you make an election, 
you may not change methods without ONRR's approval. If ONRR accepts 
your request to change methods, you may use your changed method 
beginning with the production month following the month when ONRR 
received your change request.
    (2) A change in ownership of a wash plant will not alter the 
depreciation schedule that the original washer/lessee established for 
the purposes of the allowance calculation.
    (3) With or without a change in ownership, you may depreciate a 
wash plant only once.
    (i) To calculate a return on undepreciated capital investment, 
multiply the remaining undepreciated capital balance as of the 
beginning of the period for which you are calculating the washing 
allowance by the rate of return provided in paragraph (k) of this 
section.
    (j) As an alternative to using depreciation and a return on 
undepreciated capital investment, as provided under paragraph (b)(3) of 
this section, you may use as a cost an amount equal to the allowable 
initial capital investment in the wash plant multiplied by the rate of 
return as determined under paragraph (k) of this section. You may not 
include depreciation in your allowance.
    (k) The rate of return is the industrial rate associated with 
Standard & Poor's BBB rating.
    (1) You must use the monthly average BBB rate that Standard & 
Poor's publishes for the first month for which the allowance is 
applicable.
    (2) You must re-determine the rate at the beginning of each 
subsequent calendar year.


Sec.  1206.470  What are my reporting requirements under an arm's-
length washing contract?

    (a) You must use a separate entry on Form ONRR-4430 to notify ONRR 
of an allowance based on washing costs that you or your affiliate 
incur(s).
    (b) ONRR may require you or your affiliate to submit arm's-length 
washing contracts, production agreements, operating agreements, and 
related documents.
    (c) You can find recordkeeping requirements in parts 1207 and 1212 
of this chapter.
    (d)(1) You must file an initial Form ONRR-4292 prior to, or at the 
same time as, the washing allowance determined under an arm's-length 
contract or no written arm's-length contract situation that you report 
on Form ONRR-4430. If ONRR receives a Form ONRR-4292 by the end of the 
month when the Form ONRR-4430 is due, ONRR will consider the form to be 
received in a timely manner.
    (2) The initial Form ONRR-4292 is effective beginning with the 
production month when you are first authorized to deduct a washing 
allowance and continues until the end of the calendar year, or until 
the termination, modification, or amendment of the applicable contract 
or rate, whichever is earlier.
    (3) After the initial period that ONRR first authorized you to 
deduct a washing allowance, and for succeeding periods, you must submit 
the entire Form ONRR-4292 by the earlier of the following:
    (i) Within three months after the end of the calendar year.
    (ii) After the termination, modification, or amendment of the 
applicable contract or rate.
    (4) You may request to use an allowance for a longer period than 
that required under paragraph (d)(2) of this section.
    (i) You may use that allowance beginning with the production month 
following the month when ONRR received your request to use the 
allowance for a longer period until ONRR decides whether to approve the 
longer period.
    (ii) ONRR's decision whether or not to approve a longer period is 
not appealable under 30 CFR part 1290.
    (iii) If ONRR does not approve the longer period, you must adjust 
your transportation allowance under Sec.  1206.466.


Sec.  1206.471  What are my reporting requirements under a non-arm's-
length washing contract or no written arm's-length contract?

    (a) You must use a separate entry on Form ONRR-4430 to notify ONRR 
of an allowance based on non-arm's-length washing costs that you or 
your affiliate incur(s).
    (b) ONRR may require you or your affiliate to submit all data used 
to calculate the allowance deduction. You can find recordkeeping 
requirements in parts 1207 and 1212 of this chapter.
    (c)(1) You must submit an initial Form ONRR-4292 prior to, or at 
the same time as, the washing allowance determined under a non-arm's-
length contract or no written arm's-length contract situation that you 
report on Form ONRR-4430. If ONRR receives a Form ONRR-4292 by the end 
of the month when the Form ONRR-4430 is due, ONRR will consider the 
form to be received in a timely manner. You may base the initial 
reporting on estimated costs.
    (2) The initial Form ONRR-4292 is effective beginning with the 
production month when you are first authorized to deduct a washing 
allowance and continues until the end of the calendar year or 
termination, modification, or amendment of the applicable contract or 
rate, whichever is earlier.
    (3)(i) At the end of the calendar year for which you submitted a 
Form ONRR-4292, you must submit another, completed Form ONRR-4292 
containing the actual costs for that calendar year.
    (ii) If coal washing continues, you must include on Form ONRR-4292 
your estimated costs for the next calendar year.
    (A) You must base the estimated coal washing allowance on the 
actual costs for the previous period plus or minus any adjustments 
based on your knowledge of decreases or increases that will affect the 
allowance.
    (B) ONRR must receive Form ONRR-4292 within three months after the 
end of the previous calendar year.
    (d)(1) For new non-arm's-length washing facilities or arrangements 
on your initial Form ONRR-4292, you must include estimates of allowable 
washing costs for the applicable period.
    (2) You must use your or your affiliate's most recently available 
operations data for the wash plant as your estimate, if available. If 
such data is not available, you must use estimates based on data for 
similar wash plants.
    (e) Upon ONRR's request, you must submit all data that you used to 
prepare your Forms ONRR-4293. You must provide the data within a 
reasonable period of time, as ONRR determines.
    (f) Section 1206.472 applies when you amend your Form ONRR-4292 
based on the actual costs.


Sec.  1206.472  What interest and penalties apply if I improperly 
report a washing allowance?

    (a)(1) If ONRR determines that you took an unauthorized washing 
allowance, then you must pay any additional royalties due, plus late 
payment interest calculated under Sec.  1218.202 of this chapter.

[[Page 43402]]

    (2) If you understated your washing allowance, you may be entitled 
to a credit without interest.
    (b) If you improperly net a washing allowance against the sales 
value of the coal instead of reporting the allowance as a separate 
entry on Form ONRR-4430, ONRR may assess a civil penalty under 30 CFR 
part 1241.


Sec.  1206.473  What reporting adjustments must I make for washing 
allowances?

    (a) If your actual washing allowance is less than the amount that 
you claimed on Form ONRR-4430 for each month during the allowance 
reporting period, you must pay additional royalties due, plus late 
payment interest calculated under Sec.  1218.202 of this chapter from 
the date when you took the deduction to the date when you repay the 
difference.
    (b) If the actual washing allowance is greater than the amount that 
you claimed on Form ONRR-4430 for any month during the period reported 
on the allowance form, you are entitled to a credit without interest.
[FR Doc. 2016-15420 Filed 6-30-16; 8:45 am]
 BILLING CODE 4335-30-P