[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]
[[Page 43337]]
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
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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
[[Page 43342]]
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