Repeal of Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform, 36934-36989 [2017-16571]
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Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations
DEPARTMENT OF THE INTERIOR
Office of Natural Resources Revenue
30 CFR Parts 1202 and 1206
[Docket No. ONRR–2017–0001; DS63644000
DR2000000.CH7000 178D0102R2]
RIN 1012–AA20
Repeal of Consolidated Federal Oil &
Gas and Federal & Indian Coal
Valuation Reform
Office of Natural Resources
Revenue, Interior.
ACTION: Final rule.
AGENCY:
The Office of Natural
Resources Revenue (ONRR) is repealing
the Consolidated Federal Oil & Gas and
Federal & Indian Coal Valuation Reform
Final Rule, published July 1, 2016, and
effective January 1, 2017.
Simultaneously, ONRR is reinstating the
valuation regulations governing the
valuation of Federal oil, Federal gas,
and Federal and Indian coal that were
in effect before January 1, 2017.
DATES: This rule is effective on
September 6, 2017.
FOR FURTHER INFORMATION CONTACT: For
questions on technical issues, contact
Elizabeth Dawson at (303) 231–3653,
Amy Lunt at (303) 231–3746, Peter
Christnacht at (303) 231–3651, or Karl
Wunderlich at (303) 231–3663.
SUPPLEMENTARY INFORMATION:
SUMMARY:
I. Background
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A. General
This final rule repeals in its entirety
the Consolidated Federal Oil & Gas and
Federal & Indian Coal Valuation Reform
Final Rule (2017 Valuation Rule) that
ONRR published in the Federal Register
on July 1, 2016 (81 FR 43338), and that
was effective on January 1, 2017. The
2017 Valuation Rule made changes to
existing regulations governing royalty
valuation and reporting practices for oil,
gas, and coal. As stated in the 2017
Valuation Rule’s preamble, the purpose
of implementing the rule was (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
revenue 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. 81 FR 43338.
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After the 2017 Valuation Rule was
published, however, ONRR discovered
several significant defects in the rule
that would have undermined its
purpose and intent. In addition, during
the same time period (July 1, 2016, to
the present) we received numerous
comments from the regulated
community and other members of the
public, both in response to the proposed
rule of repeal that we published in the
Federal Register on April 4, 2017, and
in other public forums, that were highly
critical of certain provisions in the rule.
In light of the defects that we discovered
in the rule and after carefully
considering all of the comments we
received, we have decided to repeal the
2017 Valuation Rule in its entirety,
principally for the following three
reasons:
First, the 2017 Valuation Rule has a
number of defects that make certain
provisions challenging to comply with,
implement, or enforce. Absent their
repeal, the rule would compromise
ONRR’s mission to collect and account
for mineral royalty revenues; could
affect royalty distributions to ONRR’s
State and Tribal partners; and would
impose a costly and unnecessary burden
on Federal and Indian lessees.
Second, On March 28, 2017, the
President issued E.O. 13783—Promoting
Energy Independence and Economic
Growth, 82 FR 16093. The executive
order directs Federal agencies to review
all existing regulations and other agency
actions and, ultimately, to suspend,
revise, or rescind any such regulations
or actions that unnecessarily burden the
development of domestic energy
resources beyond the degree necessary
to protect the public interest or
otherwise comply with the law. Based
on our own internal review, as well as
on the comments we received both
before and during the process of
promulgating this rule of repeal, we
have concluded that certain provisions
of the 2017 Valuation Rule would
unnecessarily burden the development
of Federal oil and gas and Federal and
Indian coal beyond the degree necessary
to protect the public interest or
otherwise comply with the law.
Third, on March 29, 2017, the
Secretary of the Interior (Secretary)
announced that he will reestablish the
Royalty Policy Committee (RPC) under
the Federal Advisory Committee Act.
The RPC will advise ONRR on current
and emerging issues related to the
determination of fair market value and
the collection of royalties from energy
and natural resources on Federal and
Indian lands. The RPC will be
composed of Federal representatives
and stakeholders from energy and
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mineral interests, academia, public
interest groups, States, Indian Tribes,
and individual Indian mineral interest
owners. The RPC will provide a forum
for engaging with key stakeholders and
the public on many of the same issues
we attempted to address in the 2017
Valuation Rule. ONRR expects that
further internal assessment and analysis
combined with consultations facilitated
by the RPC’s reestablishment will lead
to the development and promulgation of
a new, revised valuation rule that will
address the various problems that have
now been identified in the rule we are
repealing.
At the same time that we are repealing
the 2017 Valuation Rule, we are
reinstating the regulations governing the
valuation of oil, natural gas, and coal
produced from Federal leases and coal
produced from Indian leases that were
in effect before January 1, 2017. These
regulations will apply prospectively to
oil, gas, and coal produced on or after
the effective date that we have specified
in the DATES section of this preamble.
We intend to apply and construe the
prior regulations in a manner consistent
with the preambles published in
conjunction with the original
rulemakings and in accordance with
administrative and judicial decisions
interpreting these regulations.
Finally, upon taking effect, this repeal
of the 2017 Valuation Rule will
supersede the notification of the
postponement of the effectiveness of the
rule that we published in the Federal
Register on February 27, 2017. 82 FR
11823. When this repeal takes effect, the
so-called administrative stay of the rule
will be lifted.
B. Secretary’s Authority To Promulgate
Regulations or Reinstate Prior
Regulations Under FOGRMA
Section 301 of the Federal Oil and Gas
Royalty Management Act (FOGRMA), as
amended, codified at 30 U.S.C. 1751,
grants the Secretary broad authority to
prescribe such rules and regulations,
issued in conformity with the
Administrative Procedure Act (APA), as
he deems reasonably necessary to create
a thorough system for collecting and
accounting for Federal and Indian
mineral royalties. FOGRMA creates the
legal framework for the collection and
accounting system, but FOGRMA also
grants the Secretary, acting through
ONRR, broad discretion as to how to
build it out. Put another way (as courts
sometimes have), FOGRMA grants the
Secretary, acting through ONRR, broad
discretion to regulate interstitially to
interpret and implement the statute.
There is not a single right way for
ONRR to exercise its congressionally
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delegated authority to interpret and
implement FOGRMA; on the contrary,
there are many ways in which ONRR
may legitimately accomplish its task, as
long as the way it chooses is consistent
with the statutory language and the
congressionally prescribed legal
framework. ONRR believes that the
prior regulations, which will be
reinstated by this final rule, are fully
consistent with FOGRMA and other
applicable federal statutes and are an
effective and efficient means of valuing
Federal and Indian minerals, as
evidenced by their long and successful
use before the promulgation of the 2017
Valuation Rule.
C. Chronology of Events Following
Promulgation of 2017 Valuation Rule
On July 1, 2016, ONRR published the
final 2017 Valuation Rule in the Federal
Register. Although the rule took effect
on January 1, 2017, first reports and
royalty payments under it were not due
until February 28, 2017.
To facilitate the transition to the new
regulations, ONRR conducted eleven
training sessions for industry reporters
in different locations between October
17, 2016, and December 15, 2016. We
designed the training sessions to
educate affected parties on how to value
production and report and pay royalties
under the 2017 Valuation Rule. The
trainings also provided a forum in
which lessees could ask us questions
about the rule and how ONRR would
implement and enforce it. At the same
time that ONRR was conducting the
trainings and reviewing comments and
questions about the rule, ONRR was also
receiving numerous written requests for
guidance that asked many of the same
questions that were being raised at the
live sessions.
The feedback we received through the
training sessions and guidance requests
revealed certain unforeseen defects in,
or unintended consequences of,
portions of the 2017 Valuation Rule.
Lessees raised multiple questions that
ONRR had not previously considered
and was not prepared or able to answer,
particularly with respect to the coal
valuation provisions. For example,
lessees argued that valuing coal based
on the first arm’s-length sale of coal as
electricity is a difficult task because the
sale price of electricity does not reflect
the value of coal in a simple, predictable
fashion—electricity markets are too
diverse and complex to trace electricity
prices back to the lease. Lessees also
asked questions about how to value coal
production in certain non-arm’s-length
transactions under the new definition of
‘‘coal cooperative.’’ And lessees asked
ONRR specific questions that we had
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not previously considered about how,
and under what circumstances, we
would implement the default provision
with respect to oil, gas, and coal. At
bottom, by the middle of December 2016
we had become aware that the rule
contained several defects that, at a
minimum, would seriously complicate,
and probably compromise, ONRR’s
ability to implement and enforce certain
provisions.
On December 29, 2016, three different
sets of petitioners, some of whom had
previously requested guidance from
ONRR, filed three separate petitions
challenging the 2017 Valuation Rule in
the United States District Court for the
District of Wyoming. The petitioners
alleged that the rule created widespread
uncertainty about reporting and
payment of royalties, and in some
respects, was unreasonably difficult to
comply with. The petitioners’
arguments echoed the questions and
concerns that had been raised at the
reporter training sessions and in various
guidance requests.
By late January 2017 we recognized
that implementing the 2017 Valuation
Rule would be contrary to the rule’s
stated purpose of offering greater
simplicity, certainty, clarity, and
consistency in product valuation. We
also recognized that the defects in the
rule were significant enough that
implementation could undermine and
compromise ONRR’s mission to collect,
account for, and verify mineral royalties
for the United States and its State and
Tribal partners.
With the February 28, 2017, reporting
deadline approaching and while we
were actively considering internally
what to do about the previously
identified defects in the 2017 Valuation
Rule, the petitioners in the litigation
sent ONRR a letter (dated February 17,
2017) requesting that ONRR postpone
the rule’s effective date. Prompted by
that request, but based on ONRR’s own
independent assessment of the defects
in the rule and the harm that could
result by requiring lessees to comply
with it, we decided that it was in the
best interest of the regulated
community, the royalty beneficiaries,
and the public in general to preserve the
regulatory status quo while the litigation
was pending. Accordingly, on February
27, 2017, we published in the Federal
Register a notification postponing the
effectiveness of the rule pursuant to 5
U.S.C. 705 of the APA, pending judicial
review. 82 FR 11823.
Meanwhile, the nation had elected a
new President in November 2016, and
the new administration had taken office
on January 20, 2017. On March 28,
2017, the President issued E.O. 13783—
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Promoting Energy Independence and
Economic Growth, 82 FR 16093, which
directed the heads of executive agencies
to review all existing regulations,
orders, guidance documents, policies,
and other similar agency actions that
potentially burden the development or
use of domestically produced energy
resources and, ultimately, to suspend,
revise, or rescind those agency actions
that do so unnecessarily. The executive
order provided additional impetus to
our ongoing review of the 2017
Valuation Rule, and we discovered
some additional substantive problems
with the rule.
As a result of all of those
developments, on April 4, 2017, we
published in the Federal Register a
notice proposing to repeal the 2017
Valuation Rule in its entirety and
soliciting public comment on the
proposal. 82 FR 16323. At the same
time, we recognized that certain
provisions in the 2017 Valuation Rule
had been, and continued to be, well
received. Therefore, concurrent with the
proposed repeal, we also published an
Advance Notice of Proposed
Rulemaking soliciting public comment
on two scenarios: (1) If the 2017
Valuation Rule were repealed, whether
a new valuation rule is needed and, if
so, what particular issues the new
valuation rule should address; and (2) if
the 2017 Valuation Rule were not
repealed, what changes should be made
to the rule (82 FR 16325, April 4, 2017).
The comment period for the proposed
repeal rule closed on May 4, 2017. We
received more than a thousand
comments from 2,342 commenters both
for and against repeal. We carefully
considered all of the comments we
received and, for the reasons discussed
further below, have decided at this time
to repeal the 2017 Valuation Rule in its
entirety. ONRR will continue to assess
the substantive issues addressed in the
2017 Valuation Rule and expects to in
the near future promulgate a new,
revised valuation rule that will address
the various problems that have been
identified in the rule we are repealing.
D. Substantive Defects in, and
Administrative Challenges Posed by, the
2017 Valuation Rule
1. Valuing Coal Using the Sale Price of
Electricity
The 2017 Valuation Rule required
lessees to value certain non-arm’s-length
sales of Federal and Indian coal based
on the first arm’s-length sale of
electricity. For several reasons we have
concluded that this provision of the rule
is unnecessarily complicated and
burdensome to implement or enforce.
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ONRR has long valued oil, gas, and
coal based on the first arm’s-length sale
of the resource because we believe that
such sales are the best indicator of
market value. In promulgating the 2017
Valuation Rule, ONRR incorrectly
assumed that it would be reasonable for
lessees to ‘‘net back’’ to the value of coal
from arm’s-length electrical sales, the
same way that lessees ‘‘net back’’ to
value from the first arm’s-length sale by
an affiliate. We also incorrectly assumed
that using such sales would accurately
reflect the value of coal because the
majority of coal mined from Federal and
Indian lands is used to generate
electricity. But we failed to fully
consider other factors that determine
what a generating company charges for
its electricity. The price of electricity
also reflects the company’s costs to
construct, operate, and maintain its
depreciable capital assets; its costs to
operate and maintain other necessary
infrastructure; its costs to comply with
applicable Federal and State laws; and
its corporate overhead and other
internal corporate costs. All of those
factors may (and do) vary from company
to company and from state to state.
Unlike an arm’s-length sale of coal,
where the sale price directly and
accurately reflects the value of the coal,
the sale price of electricity is
determined by many factors in addition
to the price of coal.
Moreover, electricity is generated,
transmitted, and distributed through
regional grids where the electricity is
maintained for delivery at specified
voltages and frequencies. The regional
grids function as pools that are fed by
electricity generated from a variety of
different resources, including natural
gas, solar, wind, geothermal, and coal.
The electricity is then sold in wholesale
markets in a variety of ways, including,
but not limited to, firm and non-firm
sales, long-term and short-term sales,
interruptible sales, and daily spotmarket sales. The markets also include
ancillary services, such as spinning and
non-spinning reserves, voltage and
frequency control, and load following.
Each of these sales commands a
different price. We have concluded at
this time that the approach taken in the
2017 Valuation Rule establishes an
unreasonable requirement for the lessee
or ONRR to dissect these services and
sales, and trace those sales back to coal
produced from the lease, particularly
because electricity generated from coal
is pooled with electricity generated from
other resources before it is sold. In
short, it would be very challenging for
lessees to calculate and pay royalties
based on the sale price of electricity and
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similarly challenging for ONRR to verify
the accuracy of those calculations.
Finally, the 2017 Valuation Rule
failed to address the increasingly
common situation in which gross
proceeds accrue to a lessee’s affiliate.
The rule stated that lessees value their
Federal and Indian coal production on
‘‘the gross proceeds accruing to you for
the power plant’s arm’s-length sales of
the electricity less applicable
transportation and washing
deductions.’’ (Emphasis added.) As used
in that regulation, the word ‘‘you’’
referred to the lessee, which the rule
defined as ‘‘any person to whom the
United States, an Indian Tribe, and/or
individual mineral owner issues a lease,
and any person who has been assigned
all or part of record title, operating
rights, or an obligation to make royalty
or other payments by the lease.’’ For
Federal and Indian coal, the definition
of lessee included ‘‘an operator, payor,
or other person with no lease interest
who makes royalty payments on the
lessee’s behalf.’’ The rule was silent,
however, on how to value coal when the
gross proceeds accrued to a lessee’s
affiliate. This oversight would have
undermined ONRR’s mission and
responsibility to collect and verify
royalties, which would have had a
direct impact on revenue accruing to
ONRR’s State and Tribal partners.
2. Definition of ‘‘Coal Cooperative’’
The 2017 Valuation Rule defined
‘‘coal cooperatives’’ to capture the
arm’s-length value of coal in those
limited circumstances in which
unaffiliated companies cooperate to
market and exchange coal for mutual
economic advantage. But the term was
defective in several respects. At bottom,
the definition was overly broad and
ambiguous and created too much
confusion to be effective or enforceable.
And because the definition was too
broad, it asked lessees to perform an
unreasonably difficult task, that is, to
value coal based on the sale price
received by a third-party company that
was neither affiliated, nor in a
contractual relationship, with the lessee.
More specifically, the 2017 Valuation
Rule did not define what entities are
included in a coal cooperative, nor did
the rule adequately identify what type
of behavior, conduct, or economic
relationships constitute a coal
cooperative. Thus, the rule did not
provide lessees with meaningful
direction to enable them to determine
whether they are part of a coal
cooperative and, if so, what other
entities may also be part of that
cooperative. Indeed, the definition was
so broad that it would have captured
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almost any entity engaged in the
production, marketing, and
transportation of coal, regardless of how
far removed that entity was from the
lessee. Consequently, it would have
been unreasonable for either ONRR or
the lessee to determine where the coal
cooperative began and where it ended.
By extension, it would have been
unreasonable for either ONRR or the
lessee to determine when the first arm’slength sale occurred. As a result, lessees
could not have valued their coal, and
ONRR (or States or Tribes, acting under
authority by ONRR) could not have
verified that value. That inadvertent and
unfortunate confusion was, of course,
directly contrary to ONRR’s intent when
it promulgated the rule.
What is more, the definition would
have required lessees to perform an
unreasonably difficult task. For
example, a federal lessee in a coal
cooperative could sell its coal to an
unaffiliated third party that is also in
the cooperative. But because the parties
are part of the same cooperative, we
would not have considered that sale to
be an arm’s-length transaction. The
third party then could have transferred
the coal to an affiliate, who could have
sold the coal at arm’s-length. Under
those circumstances, the rule would
have required the lessee to value its coal
based on the sales price received by the
third-party’s affiliate, a company that
was neither affiliated, nor in a
contractual relationship, with the lessee.
Under this scenario, the lessee probably
could not have obtained the sales price
information it needed to determine the
royalty-bearing value of its coal.
Last, the definition of coal cooperative
was unnecessary because it attempted to
solve a problem that was already
addressed by the prior (and soon-to-bereinstated) regulations. In the example,
under the prior regulations ONRR
would still obtain fair market value for
the coal because the lessee and third
party lack opposing economic interests,
and we therefore would apply the
provision in the regulations for valuing
coal in non-arm’s-length transactions.
Under that provision, depending on the
circumstances, ONRR could still value
the coal based on the first arm’s-length
transaction under the fourth benchmark
in 30 CFR 1206.257(c)(2) (Federal coal)
or 1206.456(c)(2) (Indian coal).
3. Default Provision
Statutes and lease terms grant the
Secretary considerable authority and
discretion to establish the reasonable
value of Federal and Indian minerals.
By promulgating the so-called default
provision, ONRR was attempting to offer
greater clarity, consistency, and
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predictability by defining when, where,
and how the Secretary would exercise
his discretionary authority to use an
alternative methodology to value
minerals. We attempted to explain that
we would invoke the default provision
only in specific and limited situations
when we could not determine whether
a lessee had properly paid royalties
under the regulations. Those situations
include when a lessee fails to provide
documents during an audit, when a
lessee engages in misconduct, when a
lessee breaches its duty to market, or
any other situation that compromises
our ability to reasonably determine the
fair market value of the oil, gas, or coal.
But because we described those
circumstances so broadly, without
limits or meaningful guidance, the rule
created more confusion and uncertainty
than it resolved.
We also failed to appreciate the
numerous administrative challenges
posed by the default provision. For
example, the 2017 Valuation Rule did
not identify who within ONRR has the
authority to invoke the default provision
or whether that decision must be
approved or may be appealed. The rule
defined ‘‘misconduct’’ so broadly that
lessees, ONRR, and ONRR’s State and
Tribal partners were left without any
meaningful guidance on what type of
misconduct triggered the default
provision. At the same time, the rule
was silent on whether ONRR must make
a formal finding of misconduct before
the default provision is invoked, who
has the authority make such a finding,
and whether such a finding is subject to
review. We believe that those
ambiguities would have led to very
inconsistent applications of the rule.
The 2017 Valuation Rule also did not
address whether the default provision
was a tool of last resort or a vehicle to
collect and verify royalties more
efficiently. For example, the rule offered
no guidance on what would happen if
ONRR invoked the default provision to
value production because the lessee
failed to provide documents necessary
to value the production, and the lessee
later produces those documents. Nor
did the rule fully explain how the
default provision interacted with
ONRR’s civil penalty regulations. For
example, if a lessee knowingly or
willfully fails to provide documents
during an audit, the rule was silent on
Federal gas
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whether ONRR would issue a civil
penalty for failing to permit an audit, or
whether ONRR would complete the
audit by valuing the production under
the default provision, or both. These
challenges, and many others, made the
default provision confusing to lessees
and would have made it difficult, for
ONRR to implement and enforce.
Finally, with or without the default
provision, ONRR already has the
authority to establish the value of
Federal and Indian minerals when we
cannot determine whether a lessee
properly paid royalties. While the
default provision was a well-intended
attempt to provide certainty and
predictability by clarifying and
codifying that authority, we now
recognize that the default provision
created more confusion, uncertainty,
and apprehension than it resolved.
4. Requirement That Arm’s-Length
Contracts Be in Writing and Signed by
All Parties
The 2017 Valuation Rule required
both lessees and their affiliates to
reduce all contracts, contract revisions,
or amendments to writing and have
them signed by all of the parties. The
rule further stated that where the lessee
did not have in place a written contract
signed by all of the parties, ONRR could
use the default provision to value the
oil, gas, or coal at issue.
Based on the comments we received,
we have reconsidered our position on
this requirement. We now agree with
the majority of commenters that this
provision of the rule is unnecessary,
overly burdensome, and potentially
defective. First, this provision
overlooked the fact that unwritten
agreements or unsigned, written
agreements may be binding, legally
enforceable contracts. Second, this
provision contradicted the definition of
‘‘contract’’ in the rule itself, which
defined ‘‘contract’’ as ‘‘any oral or
written agreement . . . that is
enforceable by law’’ and which did not
require the contract to be signed by the
parties. Third, the preamble stated that
ONRR could discount or ignore an
arm’s-length contact if the contract were
not in writing and signed by all of the
parties, which ran counter to ONRR’s
long-held position that arm’s-length
sales are the best indicator of market
value. Fourth, the rule required the
Federal oil
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lessees’ affiliates to have all of their
contracts, contract revisions, and
amendments reduced to writing and
signed by all of the parties, despite the
fact that the affiliates are not Federal or
Indian lessees and the rule was not
purporting to regulate them. And fifth,
the rule burdened lessees and their
affiliates with an unnecessary and
potentially costly obligation to conform
contracts to meet ONRR’s specifications,
which could increase the cost of
production and delay the delivery of
mineral resources.
5. Valuation Guidance and
Determinations
The 2017 Valuation Rule required
Federal oil and gas and Indian coal
lessees to request valuation
determinations from ONRR that,
because of an oversight in the rule, we
would no longer have the regulatory
authority to issue. The prior regulations
authorized ONRR to issue a binding
valuation determination in response to
a request from an oil, gas, or coal lessee.
The 2017 Valuation Rule, however,
inadvertently stripped ONRR of that
authority or, at the very least, was
unclear as to whether ONRR could
continue to exercise that authority.
More specifically, sections 1206.108
(Federal oil), 1206.148 (Federal gas),
1206.258 (Federal coal), and 1206.458
(Indian coal) all provided that a lessee
could request a valuation determination
from ONRR. The rule then provided that
ONRR could do one of three things in
response to the request: (1) Request that
the Assistant Secretary for Policy
Management and Budget issue a
determination; (2) decide that ONRR
will issue non-binding guidance; or (3)
notify the lessee that ONRR will not
provide a determination or guidance.
The rule was silent, however, on
whether ONRR could issue a valuation
determination in response to a request.
Thus, under the 2017 Valuation Rule
ONRR arguably had no authority to
continue to issue valuation
determinations.
This was particularly problematic
because several sections in the 2017
Valuation Rule required lessees to
request valuation determinations from
ONRR, and several other provisions
required ONRR to issue such
determinations. Those references appear
in the following sections:
Federal coal
1206.111(d)
1206.252(b)(2)
1206.261(c)
1206.268(c)
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Indian coal
1206.452(b)(2)
1206.461(c)
1206.468(c)
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Federal gas
Federal oil
Federal coal
Indian coal
1206.160(c)
At bottom, this oversight means that
lessees cannot comply with the 2017
Valuation Rule and ONRR cannot
enforce it, which undermines the
purpose and intent of the rule. Even if
ONRR could issue valuation
determinations in the absence of a
regulation, these sections fail to specify
whether ONRR’s determinations are
binding on ONRR or the lessee, and if
so, whether the lessee may appeal the
determination. Other provisions of the
regulations cross-reference the terms
‘‘valuation determinations’’ and
‘‘determinations’’ without defining
those terms or stating whether those
terms are synonymous or distinct. In
addition, section 1206.458, which
applies to Indian coal, incorrectly
provides that the Assistant Secretary for
Policy, Management and Budget will
issue a valuation determination
regarding Indian coal. But only the
Assistant Secretary for Indian Affairs
has the authority to issue a valuation
determination for questions concerning
Indian lands. All in all, the numerous
defects and the lack of consistency in
the regulations governing valuation
determinations undermined the purpose
and intent of the rule and would have
created confusion and inefficiencies and
imposed additional burdens on both
ONRR and the regulated community.
sell gas produced from the same lease at
arm’s-length, we assumed that the lessee
would propose to value its vented and
flared gas on the price it received in the
arm’s-length sale. Thus, those lessees
would have reported one volume, on
one line, pursuant to a single valuation
method.
Lessees in the San Juan Basin in New
Mexico, however, would have been held
to a different standard. Because there is
a viable index price in the San Juan
Basin, lessees there would be required
to value their gas using the index price.
That is true even if the lessee were
selling the same gas from the same lease
at arm’s length to third-party buyers.
Under those circumstances, the lessee
would be required to report two
separate volumes, on two separate lines,
using two separate valuation methods.
This inconsistency, and the additional
administrative burden it would impose
on certain lessees, was not our intent
when we promulgated the rule.
In sum, the 2017 Valuation Rule
would have imposed an unnecessary
and potentially costly administrative
burden on certain lessees. At the same
time, the rule would run counter to
ONRR’s long-held belief and position
that prices under arm’s-length contracts
are the best measure of value.
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6. Flared Gas Valuation
7. Changes in Administration and
Energy Policy
Under the 2017 Valuation Rule,
lessees who are required to pay royalty
on flared gas would have been required
to value the vented and flared gas using
an index price for the area if one is
available. If an index price were not
available, then the lessee would have
been required to propose a method to
ONRR under the default provision. In
those circumstances, we expected that
the proposed method would value the
vented and flared gas based on the
arm’s-length sale price the lessee
received for other gas sold from the
same lease. ONRR now recognizes that
this regulation would have imposed an
unnecessary and potentially costly
administrative burden on certain
lessees. It would also have run counter
to ONRR’s belief and position that
arm’s-length transactions are the best
indicator of value.
For example, there is no viable index
price in North Dakota. Thus, lessees in
North Dakota would have been required
to propose a method to ONRR under the
default provision. For lessees that also
The nation elected a new President in
November 2016, and the new
administration took office on January
20, 2017. Through various public
announcements the new administration
quickly signaled that it would adopt and
follow a national energy policy different
than that of its predecessor, one that
emphasized and prioritized the
reduction of Federal regulatory burdens
on industry. On March 28, 2017,
President Donald J. Trump issued E.O.
13783—Promoting Energy
Independence and Economic Growth
(Executive Order) (82 FR 16093, Mar.
31, 2017). The Executive Order begins
by stating broadly that ‘‘[i]t is in the
national interest to promote clean and
safe development of our Nation’s vast
energy resources, while at the same time
avoiding regulatory burdens that
unnecessarily encumber energy
production, constrain economic growth,
and prevent job creation.’’ The
Executive Order then continues,
‘‘Accordingly, it is the policy of the
United States that executive
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departments and agencies (agencies)
immediately review existing regulations
that potentially burden the development
or use of domestically produced energy
resources and appropriately suspend,
revise, or rescind those that unduly
burden the development of domestic
energy resources beyond the degree
necessary to protect the public interest
or otherwise comply with the law.’’ To
that end, the Executive Order directs the
heads of all agencies to ‘‘review all
existing regulations, orders, guidance
documents, policies, and any other
similar agency actions (collectively,
agency actions) that potentially burden
the development or use of domestically
produced energy resources, with
particular attention to oil, natural gas,
coal, and nuclear energy resources.’’
The Executive Order defines ‘‘burden’’
to mean ‘‘to unnecessarily obstruct,
delay, curtail, or otherwise impose
significant costs on the siting,
permitting, production, utilization,
transmission, or delivery of energy
resources.’’
Pursuant to the Executive Order,
ONRR included the 2017 Valuation Rule
in its review of regulations that
potentially burden the development or
use of domestically produced energy
resources. As a result of that review, we
concluded that the rule, as a whole,
would unduly burden or unnecessarily
obstruct, delay, curtail, or otherwise
impose significant costs on the
production, utilization, or delivery of
Federal oil or gas or Federal or Indian
coal. For example, because we realized
that valuing coal based on the arm’slength sale of electricity is a very
challenging task, we concluded that
Federal and Indian coal lessees would
incur unnecessary and unwarranted
costs in trying to comply with those
provisions in the 2017 Valuation Rule.
Likewise, because we had realized that
the definition of ‘‘coal cooperative’’ in
the rule was too broad and ambiguous
to comply with or enforce, we
concluded that lessees in cooperatives
would incur unnecessary and
unwarranted costs in an effort to
determine the royalty-bearing value of
their coal. These defects alone would
have resulted in significant costs that
would have served as a financial
disincentive to producing coal from
Federal or Indian lands.
In sum, a number of provisions of the
2017 Valuation Rule would have
unnecessarily obstructed, delayed,
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curtailed, or otherwise imposed
significant costs on the production,
utilization, or delivery of Federal oil
and gas and Federal and Indian coal.
The repeal of the 2017 Valuation Rule
therefore is consistent with the policy
announced in the Executive Order and
the direction that the Executive Order
provides to executive agencies. The
Department takes seriously its
responsibility to ensure that taxpayers
receive the full value from Federal
mineral leases, which is why ONRR
intends to continue to consider future
changes and develop a new rulemaking
after further analysis and consultations
with our key stakeholders and the
general public.
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II. Comments on Proposed Rules
On April 4, 2017, ONRR published a
Notice of Proposed Rulemaking (NPRM)
to invite public comment on the
possible repeal of the 2017 Valuation
Rule. 82 FR 16323. During the 30-day
public comment period, we received
more than one thousand pages of
written comments from over 2,342
commenters. We received comments
from industry, industry trade groups,
Members of Congress, State governors
and agencies, local municipalities,
Tribes, local businesses, public interest
groups, and individual commenters.
The majority of comments—both those
opposing and those supporting repeal—
addressed the Federal and Indian coal
valuation provisions in the 2017
Valuation Rule.
Comments opposing repeal of the
2017 Valuation Rule generally argued
that repealing the 2017 Valuation Rule
would result in undervaluing our
nation’s oil, gas, and coal resources;
would result in a waste of government
resources; and would violate certain
provisions in the APA.
Comments supporting repeal of the
2017 Valuation Rule generally faulted
the following elements of the rule: (a)
The method that lessees must use to
calculate value on coal sold under nonarm’s-length contracts; (b) ONRR’s
definition of ‘‘contract’’ and
‘‘misconduct’’; (c) the default provision;
(d) changes to transportation and
processing allowances; (e) the option to
value Federal gas sold under non-arm’slength transactions based on index
prices; and (f) percentage-of-proceeds
contracts.
A. General Comments
Public Comment: Many commenters
who work in the coal industry or live in
coal-mining-dependent communities,
including a tribe, maintained that the
2017 Valuation Rule went too far. They
argued that the 2017 Valuation Rule
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imposed unwarranted valuation
methods, which, they contended, hinder
transparency and create complex and
subjective oil, gas, and coal valuations.
They claimed that the 2017 Valuation
Rule would cause economic harm to the
oil, gas, and coal industries, including
the loss of jobs.
ONRR also received a few comments
advocating that oil, gas, and coal
production should stop and that the
minerals should ‘‘stay in the ground.’’
ONRR Response: We agree that the
2017 Valuation Rule’s process for using
the sale price of electricity to value coal
would be too complex to comply with,
implement, or enforce. We also agree
that other aspects of the 2017 Valuation
Rule, including the default provision
and the definition of coal cooperative,
are too broad to be implemented
effectively, which could make reporting
and paying royalties more burdensome
and less predictable and transparent.
Although we appreciate the
comments regarding keeping fossil fuels
in the ground and the socioeconomic
impact of the 2017 Valuation Rule on
communities that rely on coal
production, both issues are beyond the
scope of this rulemaking.
Public Comment: An industry trade
group commented that complexities in
the 2017 Valuation Rule would make it
difficult for small businesses to comply.
The commenter also claimed that
smaller companies would not be able to
take deductions, resulting in a higher
royalty rate.
ONRR Response: For the reasons
stated previously, we agree that
implementing the rule would increase
the costs of compliance and
unnecessarily burden the production of
Federal and Indian mineral resources.
We also agree that those increased
compliance costs could
disproportionately impact smaller
companies that have fewer resources to
comply.
Public Comment: We received
comments from two States asserting that
repealing the rule would unfairly reduce
the royalties that the States receive
under the 2017 Valuation Rule.
Conversely, we received a comment
from another State asserting that not
repealing the rule would result in
decreased production that would
adversely affect its royalty share.
ONRR Response: Based on our
economic analysis, we recognize that
repealing the 2017 Valuation Rule will
result in a decrease in royalties
(between 0.8 percent and 1.0 percent) to
our State partners compared to what
they would receive if ONRR
implemented and enforced the rule.
ONRR will continue to assess options
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for updating our valuation regulations
and expects to, in the near future,
propose new rules that could offset, in
whole or in part, the decrease in
royalties shared with State partners in
future years compared to what would
otherwise result from the repeal of the
2017 Valuation Rule. As discussed
previously, the rule has a number of
defects that make certain provisions
challenging to comply with, implement,
or enforce. ONRR’s attempt to
implement or enforce the rule as written
would have compromised our ability to
collect and account for mineral royalty
revenues, which in turn may have
affected distributions to other royalty
beneficiaries. It would also have
imposed an additional financial and
administrative burden on our State and
Tribal partners, who audit and verify
royalty payments.
We also agree with the State
commenter that implementing the 2017
Valuation Rule could result in some
decreased production, particularly for
coal, because the burden of complying
with certain provisions of the rule
would serve as a disincentive to
production. This too would result in
decreased royalty distributions to our
State and Tribal partners. All told, we
believe that the modest economic gains
that might result from implementing the
rule are far outweighed by the
potentially significant burden on
industry, ONRR, and our State and
Tribal partners from implementing and
enforcing a rule with significant defects.
Public Comment: Industry trade
groups claimed that the 2017 Valuation
Rule was unnecessarily complex, which
would increase the costs of complying
with the regulation. The groups
maintained that the complexity and
costs would discourage industry from
entering into Federal or Indian leases.
ONRR Response: ONRR agrees that
several unforeseen defects in the 2017
Valuation Rule have the potential to
significantly increase the cost and
administrative burden of compliance,
which could create a disincentive to
entering into, and producing oil, gas,
and coal from, Federal or Indian leases.
Public Comment: We received
comments encouraging collaboration
with our stakeholders in any future
rulemaking. Many industry commenters
encouraged working through the RPC to
advise ONRR on valuation policies.
ONRR Response: As discussed
previously, the Secretary has recently
re-established the RPC to collaborate
with our stakeholders in any future
rulemaking. The RPC will provide a
forum for engaging with the public on
many of the same issues we attempted
to address in the 2017 Valuation Rule.
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C. Administrative Procedure Act (APA)
We look forward to working with our
stakeholders in the RPC on a future
rulemaking.
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B. Fair Return to Government
Public Comment: Many commenters
and comments disagreed about the need
either to revise or to repeal the 2017
Valuation Rule. Some public interest
groups and some members of the public
asserted that ONRR’s regulations have
undervalued royalties for many years
and that the changes made in the rule
would ensure that royalties are based on
fair market value. Industry trade groups
and other members of the public
maintained that the rule would result in
values that inflate the value of the
resources.
ONRR Response: We disagree that
repealing the rule will prevent the
government from receiving a fair market
value for its mineral resources. The
prior (and soon-to-be-reinstated)
regulations have been in place for more
than twenty years and serve as a
reasonable, reliable, and consistent
method for valuing Federal and Indian
minerals for royalty purposes. This is
evidenced by the fact that when we
promulgated and published the final
2017 Valuation Rule, we estimated that
it would generate less than 1 percent in
additional royalties. 81 FR 43359.
Moreover, as we discussed in proposing
the 2017 Valuation Rule, we were
attempting to make ‘‘proactive and
innovative changes’’ to the rules ‘‘to
increase the effectiveness and efficiency
of the rules.’’ We believe today, as we
always have, that the prior (and soon-tobe-reinstated) regulations provide a fair
market return for Federal and Indian
minerals. That said, we will continue to
look for opportunities to improve our
regulations, including opportunities to
improve the return to taxpayers and
Indian mineral owners and to
streamline processes for both ONRR and
industry.
Public Comment: A public interest
group maintained that our regulations
should use a market value based on the
value of the resource where it is
ultimately consumed. The comment
asserted that ONRR does not collect
royalties at the market and that we
should more aggressively pursue a value
at the market instead of a value at the
lease.
ONRR Response: While we appreciate
the comment, whether ONRR should
use a market value based on the value
of the resource where it is ultimately
consumed is outside the scope of this
rulemaking.
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One member of Congress, two State
officials, and several public interest
groups asserted that ONRR failed to
comply with certain requirements in the
APA.
Public Comment: Some commenters
stated that ONRR’s decision to postpone
the effectiveness of the 2017 Valuation
Rule indicates ONRR’s intent to repeal
the rule, without regard to any
comments received in a rulemaking
process, in violation of APA rulemaking
requirements.
ONRR Response: The 2017 Valuation
Rule was effective on January 1, 2017.
On February 27, 2017, for the reasons
discussed in the preamble to this rule,
including the filing of three separate
petitions challenging the rule in the
United States District Court for the
District of Wyoming, ONRR postponed
the effectiveness of the rule, pending
judicial review. 82 FR 11823. ONRR did
not decide to repeal the 2017 Valuation
Rule, however, until after we had
reviewed and considered of all
comments that we received in response
to the proposed rule of repeal, which we
published in the Federal Register on
April 4, 2017. 82 FR 16323.
Public Comment: We also received
comments contending that ONRR did
not provide a reasoned basis to repeal
the rule.
ONRR Response: We are providing a
reasoned basis to repeal the rule in the
preamble to this rule. Before we
proposed to repeal the 2017 Valuation
Rule, we identified several defective
provisions in the rule that would have
made these provisions unnecessarily
complicated and burdensome to comply
with, implement, or enforce. When we
published the proposed rule of repeal
on April 4, 2017, we identified some of
those defects and specifically invited
public comment on them as well as on
other aspects of the 2017 Valuation
Rule.
Public Comment: Public interest
groups and some individuals claimed
that the 30-day comment period in the
NPRM is unreasonable and violates the
APA. The commenters asserted that
ONRR went to great effort to promulgate
the 2017 Valuation Rule and was now
proposing to repeal it with only a 30day comment period.
ONRR Response: Under the APA’s
rulemaking procedures, agencies must
publish a notice of proposed rulemaking
in the Federal Register; allow interested
persons an opportunity to comment on
the proposed rule; and, after considering
those comments, publish the final rule.
The APA requires an opportunity to
submit ‘‘written data, views, or
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arguments,’’ yet there is no required
minimum comment period under the
APA. See 5 U.S.C. 553(c). Through this
rulemaking we are complying with the
requirements set forth in the APA. We
provided a reasonable amount of time to
allow interested parties a sufficient
opportunity to consider the repeal and
its supporting analysis and to provide
meaningful comments.
Public Comment: One commenter
asserted that ONRR must analyze the
record compiled to issue the rule and
provide a reasoned explanation for the
repeal. According to the commenter,
ONRR has not cited any new scientific
or technical information in support of
repeal.
ONRR Response: The comment is not
clear on whether it refers to the record
for the 2017 Valuation Rule or the
record for the repeal of the 2017
Valuation Rule. Regardless, we provided
the purpose and justification for both
rules and responded to comments that
we received during both rulemakings.
Specifically, we analyzed the record
compiled during the 2017 Valuation
Rule rulemaking. 81 FR 43338. In the
preamble and responses to comments
for this final rule, ONRR also analyzed
the record compiled for the proposed
repeal. We have determined to repeal
the 2017 Valuation Rule for the reasons
stated herein.
D. Government Efficiency
Public Comment: One member of
Congress and a public interest group
asserted that repealing the rule amounts
to wasting government resources
because ONRR is abandoning the work
that it performed while promulgating
the 2017 Valuation Rule. These
commenters also argued that if there are
problems with the rule, ONRR should
address those problems separately and
not necessarily abandon the rule in its
entirety.
ONRR Response: We disagree that
repealing the rule is a waste of
government resources. As noted
previously, the 2017 Valuation Rule has
several defects that make certain
provisions unnecessarily complicated
and burdensome to comply with,
implement, or enforce. We have
concluded that those defects are
significant enough that implementing
the rule would compromise our mission
to collect and account for mineral
royalty revenues for Federal oil and gas
and Federal and Indian coal. The cost of
implementing the rule and subsequently
trying to fix the defects in one or more
separate rulemakings would far exceed
the cost of repealing and replacing the
rule.
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We also disagree that ONRR is
abandoning the work that it previously
performed. As noted previously, the
Secretary is reestablishing the RPC to
increase stakeholder engagement on
many of the same issues the 2017
Valuation Rule attempted to address.
We hope and expect that this new round
of public engagement will lead to the
development of a new valuation rule.
The work that ONRR performed while
promulgating the 2017 Valuation Rule,
as well as the stakeholder comments
during that rulemaking, will no doubt
serve as valuable resources for the RPC
as it fulfills its charge to advise ONRR
on current and emerging issues related
to the determination of fair market value
and the collection of royalties from
resources on Federal and Indian lands.
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E. Federal and Indian Coal Valuation
For coal not sold under arm’s-length
contracts, the 2017 Valuation Rule
removed the ability for lessees to use the
benchmarks found in the prior (and
soon-to-be-reinstated) regulations.
Instead, under the 2017 Valuation Rule
lessees had to value their coal on the
first arm’s-length sale of the coal. In
cases where that first arm’s-length sale
was for the sale of electricity, lessees
had to use the prices that they received
for electricity to ‘‘net back’’ to the value
of the coal at the lease.
1. Valuing Coal Based on Benchmarks
Public Comment: ONRR received
numerous comments from industry,
government officials, industry trade
groups, public interest groups, and the
general public regarding how lessees
should value Federal and Indian coal
not sold at arm’s length.
Some commenters maintained that
the prior rule’s non-arm’s-length
valuation benchmarks fail to capture the
true value of coal that lessees sell in
non-arm’s-length transactions. The
commenters posited that the
benchmarks do not allow ONRR to
determine royalty value based on a coal
lessee’s affiliate’s subsequent arm’slength sale, including overseas sales,
resulting in the coal industries taking
advantage of a ‘‘loophole.’’ These
commenters maintained that the most
effective method to determine the value
of Federal and Indian coal not sold
under arm’s-length contracts is to use
the first arm’s-length sale of coal sold by
the lessee’s affiliate.
ONRR also received comments from
industry, government officials, industry
trade groups, and the general public that
supported repealing the rule because
they found the old benchmarks to be
time-tested and robust. These
commenters maintained that the 2017
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Valuation Rule’s method to determine
value for royalty purposes when Federal
and Indian lessees do not sell their coal
at arm’s-length was difficult to
implement and did not establish an
appropriate value, for royalty purposes,
of Federal or Indian coal at the mine.
One commenter asserted that the rule
amounted to an unlawful royalty on the
value of services that an affiliate
provides to the lessee.
ONRR Response: We believe that
arm’s-length transactions generally are
the best indicators of market value
because they provide a consistent and
accurate measure of value. But we do
not agree that the benchmarks in the
prior (and soon-to-be-reinstated)
regulations create a ‘‘loophole’’ that
permits coal lessees to shirk their
royalty obligations. Indeed, ONRR has
used the benchmarks to order additional
royalties due based on an affiliate’s
arm’s-length sale, including in those
circumstances in which the coal is sold
by the affiliate in the international
market. While we recognize that the
benchmarks are sometimes difficult to
apply, we also recognize that
benchmarks are a proven and timetested method for determining the fair
value of Federal and Indian coal that the
lessee does not sell at arm’s-length.
2. Valuing Coal Based on ‘‘Net Back’’
From Electric Sales
Public Comment: Numerous coal
companies and a coal industry trade
group expressed a range of concerns
about using electric sales to value coal
sold in non-arm’s-length situations
without competing economic interests.
In particular, these commenters
highlighted extraordinary complexities
in electric markets and the electric
producers’ resource portfolios. They
objected to valuing coal by way of
electricity, which the commenters
asserted is a separate commodity subject
to its own unique market factors and
forces and regulatory requirements, and
argued that geothermal regulations were
inappropriate as a means for
determining transmission and
production allowances. Overall,
industry commenters argued that the
2017 Valuation Rule’s effort to value
coal through arm’s-length sales of
electricity was overly burdensome if not
functionally impossible. A number of
comments from the general public also
asserted that valuing coal as electricity
would make electricity more expensive
because the increased royalty burden
would be passed on to the consumer.
ONRR Response: ONRR has carefully
considered these comments and, as
discussed in the preamble to this rule,
has concluded and agrees that the 2017
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Valuation Rule’s process for ‘‘netting
back’’ to the value of coal from arm’slength electrical sales is an
unnecessarily complicated and
burdensome task to perform and does
not necessarily result in an accurate
valuation of the coal.
3. Other Issues Related to Valuing Coal
Public Comment: Two companies, one
State government representative, three
industry trade groups, and one member
of the public supporting the repeal
observed that the 2017 Valuation Rule
handles coal lessees differently than oil
and gas lessees and claimed that this
treatment is discriminatory. They
pointed out that, like coal, gas can be
used to generate electricity, but that,
unlike coal, ONRR does not require
Federal or Indian gas lessees to value
their gas production based on electricity
sales ‘‘netted back’’ to the lease.
ONRR Response: We did not intend to
discriminate against coal by valuing the
coal based on electricity sales. Coal, oil,
and gas are all different commodities,
subject to different market factors and
forces and regulatory requirements. In
our experience, the first arm’s-length
sale of much Federal or Indian coal is
as electricity. That is rarely the case for
Federal or Indian oil and gas.
Public Comment: One company
suggested that the costs to comply with
the 2017 Valuation Rule’s non arm’slength coal valuation provisions would
offset any increase in royalty that ONRR
would receive. The company further
claimed that ONRR’s own analysis
shows that the royalties received from
these provisions would be minimal if
not negative.
ONRR Response: We agree that the
2017 Valuation Rule’s requirement to
value coal based on electric sales is
overly burdensome and would result in
substantial compliance costs.
F. Definitions
1. Misconduct
The 2017 Valuation Rule included a
new definition of ‘‘misconduct’’ to use
in conjunction with the default
provision.
Public Comment: One member of the
public took issue with the 2017
Valuation Rule’s definition of the term
‘‘misconduct.’’ The commenter
maintained that the term has derogatory
implications that could affect a lessee’s
reputation. The commenter noted that
the definition added tension between
ONRR and the industry that it regulates.
ONRR Response: We defined
‘‘misconduct’’ to clarify when ONRR
would use its discretion to determine
the value of production under the
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default provision. We now believe the
definition is too ambiguous because it
provides almost no guidance as to what
type of conduct qualifies as misconduct.
At the same time, the rule is silent on
whether ONRR must make a formal
finding of misconduct before the default
provision is invoked, who has the
authority make such a finding, and
whether such a finding is reviewable on
appeal. Taken together, these
ambiguities could lead to inconsistent
applications of the rule, which would
undermine the purpose and intent of the
rule. While we cannot surmise how a
finding of misconduct would impact a
lessee’s reputation, we do agree with the
commenter that the ambiguity of the
definition perpetuated (and perhaps
aggravated) the tension and
apprehension that we were attempting
to rectify.
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2. Coal Cooperative
The 2017 Valuation Rule added a new
definition of the term ‘‘coal
cooperative’’ that included 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 company
asserted that, by determining in advance
that transactions between coal
cooperatives are non-arm’s-length,
ONRR failed to take into account its
longstanding criteria for determining
whether entities are affiliated. The
commenter further contended that
ONRR has not provided any evidence to
support that coal cooperatives are
engaging in non-arm’s-length
transactions. The company concludes
that this is arbitrary, capricious, and
contrary to law.
ONRR Response: For the reasons
discussed in the preamble to this rule,
we agree that the definition of coal
cooperatives in the 2017 Valuation Rule
is overly broad and ambiguous and
would create too much confusion to be
effective or enforceable. We also agree
that the definition is unnecessary
because ONRR can evaluate such
transactions on a case-by-case basis
under the prior (and soon-to-bereinstated) regulations.
G. Default Provision
The 2017 Valuation Rule included the
so-called default provision, which
allowed ONRR great discretion to value
a lessee’s oil, gas, and coal production
in circumstances in which we could not
determine whether a lessee properly
paid royalties under the regulations. We
explained that such circumstances
included, but were not limited to, the
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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
using other measures of value.
Public Comment: Companies and
industry trade groups overwhelmingly
opposed the default provision. Many
general public commenters also
opposed it. The commenters asserted
that the default provision gave ONRR
‘‘overly broad’’ discretion to determine
the value of production. An oil and gas
industry trade group asserted that the
default provision allowed ONRR to
‘‘second guess’’ lessees’ reporting and
payment in subsequent years,
potentially causing lessees to incur late
payment interest and penalties. A State
official raised concerns that the default
provision could have a chilling effect on
coal production from Federal and
Indian lands.
Public interest groups and other
members of the general public approved
of the default provision, at least in
principle. These commenters asserted
that eliminating the default provision
would hinder ONRR’s ability to ensure
a fair value of Federal and Indian
mineral resources, specifically for coal.
One public interest group stated that the
default provision simply codified the
Secretary’s authority to determine
royalty value and clarified when and
how ONRR anticipated using that
authority.
ONRR Response: The comments alone
demonstrate how the default provision
created far more confusion, uncertainty,
and apprehension than we intended or
anticipated. Under FOGRMA, as
amended, the Secretary indisputably
has the authority and discretion to
determine the reasonable value of
Federal and Indian minerals. By
promulgating the default provision, we
attempted to offer greater clarity,
consistency, and predictability by
defining when, where, and how ONRR
would value production in those
circumstances in which we could not
determine whether a lessee properly
paid royalties under the regulations. We
drafted the rule broadly to encompass
every scenario in which ONRR would
be forced to invoke the default
provision. We realize now that in doing
so, we provided little in the way of
meaningful guidance on how and when
ONRR would invoke its authority.
Moreover, because the rule was so
broad, it created the perception that
ONRR would look past the valuation
regulations and value production under
the default provision regardless of
whether the lessee properly reported
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and paid royalties under our
regulations. This widespread confusion
defeated the very purpose and intent of
including a default provision in the
rule.
Also, we disagree with those
commenters who claimed that
eliminating the default provision would
hinder ONRR’s ability to ensure a fair
value of Federal and Indian mineral
resources. Indeed, with or without the
default provision, ONRR has the
authority to establish the value of
Federal and Indian minerals when we
cannot determine whether a lessee
properly paid royalties under the
regulations. ONRR exercised this
authority under our prior regulations,
and we will continue to exercise that
authority now that those regulations
will be reinstated. Typically we use this
authority in limited circumstances to
establish a reasonable value of
production using market-based
transaction data, which has always been
the basis for our royalty valuation rules.
Therefore, the repeal of the default
provision will have the same small and
speculative royalty impact as its
implementation.
H. Allowances
In the 2017 Valuation Rule ONRR
eliminated the regulation allowing us to
approve transportation allowances in
excess of 50 percent of the value of a
lessee’s oil production. The rule also
eliminated lessees’ ability to net
transportation costs in their gross
proceeds calculations (‘‘transportation
factors’’). The 2017 Valuation Rule also
eliminated both our ability to grant
extraordinary processing allowances
and to approve requests for lessees to
exceed the 662⁄3 percent limitation on
processing allowances.
Public Comment: Coal companies and
coal industry trade groups asserted that
coal transportation allowances were
poorly defined. They also objected to
the 2017 Valuation Rule’s requirement
that they use the geothermal allowance
regulations to ‘‘net back’’ to the value of
coal where the first arm’s-length sale is
electricity. Oil and gas industry
unanimously opposed the rule’s cap on
transportation and processing
allowances of 50 percent and 662⁄3
percent, respectively.
Public interest groups generally
opposed repealing the allowance
provisions in the 2017 Valuation Rule.
Some commenters suggested that
allowance caps create more
transparency and are easier to enforce.
One public interest group advocated for
eliminating all allowances, suggesting
that they are a form of subsidy. Another
public interest group reiterated its view
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that coal transportation and washing
allowances should, like oil and gas, be
limited to 50 percent and 662⁄3 percent,
respectively. A member of the general
public asserted that ONRR should give
standard deductions for transportation
and coal washing to reduce
administrative burden and to ensure a
fair return to taxpayers.
ONRR Response: We appreciate the
variety of responses, but whether ONRR
should eliminate all transportation
allowances or establish a standard
allowance are questions that are outside
the scope of this rulemaking. The
United States shares in certain expenses
that occur downstream or away from the
lease, including costs associated with
transportation, gas processing, and coal
washing, because the United States
benefits from lessees selling their
production at a market instead of at the
lease.
We agree that, in practice, the
requirement that coal lessees use the
geothermal allowance regulations to
‘‘net back’’ to the value of coal where
the first arm’s-length sale is electricity is
unnecessarily complicated and
burdensome. While we disagree that the
provisions in the 2017 Valuation Rule
that would have capped oil and gas
transportation allowances were arbitrary
and capricious, we recognize that each
cap would impose additional costs on
some operators.
Public Comment: ONRR received
comments from industry trade groups
stating that the 2017 Valuation Rule
arbitrarily reversed a longstanding deepwater-gathering policy that permitted
lessees to take transportation allowances
for moving oil and gas production on
the OCS.
In contrast, a public interest group
asserted the deep-water-gathering policy
allowed improper deductions under
ONRR’s regulatory scheme prior to the
2017 Valuation Rule. The commenter
maintained that repealing the 2017
Valuation Rule removes language that
ensures appropriate deep-water
transportation allowances.
ONRR Response: By repealing the
2017 Valuation Rule and reinstating the
prior regulations, ONRR’s longstanding
deep-water-gathering policy will remain
in effect, and ONRR will continue to
implement it to the extent that it is
consistent with the prior regulations.
Nonetheless, ONRR believes that the
deep-water-gathering policy is a matter
that is appropriate to revisit and
reconsider. ONRR will be further
considering this matter, including
through consultations as part of the RPC
process.
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I. Index-Based Gas Valuation Option
The 2017 Valuation Rule added an
index-price valuation method that
lessees who do not sell their gas under
an arm’s-length sale could have elected
to use in lieu of valuing their gas on
their first arm’s-length sale. ONRR based
the method on publicly-available index
prices, less a specified deduction to
account for processing and
transportation costs.
Public Comment: An industry trade
group and a member of the public cited
the shortcomings in the index-based gas
valuation option as one reason for
repealing the 2017 Valuation Rule.
While they supported the use of indexbased valuation in concept, they argued
that the index-based valuation option in
the rule is unreasonable and, at times,
arbitrary for the following reasons: (1)
ONRR did not provide the option to
arm’s-length lessees; (2) the index
option could result in a price so high
that it would disincentivize lessees from
using it; (3) the adjustments for
transportation and processing were too
low; and (4) ONRR did not provide any
standards for when and why it might
change the adjustments.
ONRR Response: We agree with the
commenters that this is an area
requiring further analysis. Given the
mutual interest in exploring indexbased valuation options, we believe the
newly re-commissioned RPC will
provide a valuable forum to engage our
stakeholders in a meaningful way on
this topic.
J. Percentage of Proceeds Contracts
Lessees sometimes sell their gas under
arm’s-length length percentage-ofproceeds (POP) contracts for a price that
is based on a specific percentage of the
proceeds that the purchaser receives
after processing the gas. The 2017
Valuation Rule required lessees with
POP contracts to report and pay
royalties as processed gas. This rule of
repeal allows lessees to report and value
POP contract sales as unprocessed gas.
Public Comment: An industry trade
group maintained that lessees would
find it difficult to value gas sold under
arm’s-length POP contracts because they
lack access to information from the
midstream processors and/or
purchasers.
ONRR Response: Our experience is
that the value lessees receive under a
POP contract is usually net of certain
costs incurred to place the gas into
marketable condition. The 2017
Valuation Rule did not change the
lessee’s obligation to ensure that it is not
deducting costs to place gas in
marketable condition at no cost to the
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36943
Federal government; repealing the rule
likewise does not change that
obligation. Nonetheless, we believe that
how to value gas sold under arm’slength POP contracts is an appropriate
topic for the RPC, and we look forward
to engaging with members of the public
and industry stakeholders to explore
different options for reporting POP
contracts.
K. Requirement of Written, Signed
Contracts
Although the 2017 Valuation Rule
defined ‘‘contract’’ to include legally
enforceable oral agreements, the rule
itself required a lessee or its affiliate to
have all of its contracts, contract
revisions or amendments in writing and
signed by all of the parties. If the lessee
did not have a written contract, signed
by all of the parties, then ONRR could
use the default provision to determine
value.
Public Comment: Several commenters
disagreed with the 2017 Valuation
Rule’s requirement that all contracts for
the sale, transportation, processing, or
washing of oil, gas, or coal be in writing
and signed by all parties to the contract.
These commenters maintained that such
a restriction ignores that unwritten and
unsigned contracts are legally
enforceable.
ONRR Response: We adopted the
requirement that all contracts be in
writing and signed by all parties to
enhance our ability to verify the
accuracy of royalty reports and
payments. For the reasons stated in the
preamble to this rule, we reconsidered
our position and now agree that this
provision is unnecessary, overly
burdensome, and potentially defective.
The prior (and soon-to-be-reinstated)
regulations do not require all contracts
to be in writing and signed by all
parties. But, under 30 CFR 1207.5, we
will continue to require lessees to place
in written form and maintain copies of
all sales contracts and to maintain
copies of other contracts and agreements
for accounting or auditing purposes.
III. Procedural Matters
A. Summary Cost and Royalty Impact
Data
The economic impact analysis that we
prepared in the 2017 Valuation Rule
used 2010 royalty data. These economic
impacts reflected market conditions—
commodity price, volumes, etc.—that
existed in 2010. In evaluating the
economic impacts of repealing the rule,
we used more recent royalty data. Using
data from 2015 versus 2010 provides an
estimate that is more in line with
current market projections of future
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commodity prices. The market for these
resources changed between 2010 and
2015, with the value of the resources
generally decreasing. Not surprisingly,
our updated analysis shows a somewhat
smaller decrease in royalty payments
compared to the analysis that
accompanies the 2017 Valuation Rule.
Overall, our estimates for the previous
rule, using 2010 data, projected costs to
industry of $74.78 million per year
(with roughly corresponding benefits to
the Treasury and States); this rule, using
2015 data, the projected costs to
industry from the 2017 Valuation Rule
total $67.4 million per year; thus repeal
of the rule results in $67.4 million in
benefits to industry (with roughly
corresponding benefits to the Treasury
and States).
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. This repeal has
cost impacts that will result in
decreased royalty collections. The net
impact of these provisions is an
estimated annual decrease in royalty
collections of between $60.1 million
and $74.8 million. This represents
between 0.8 percent and 1.0 percent of
the total Federal oil, gas, and coal
royalties that we collected in 2015.
Although the 2017 Valuation Rule was
stayed before the first reporting and
payments were due, some lessees had
already implemented changes in their
related systems and reporting
procedures. Therefore, some lessees
may incur additional costs from
implementing this rule because some
lessees may have to undo the system
changes that they put in place in
anticipation of first reporting under the
2017 Valuation Rule on February 28,
2017. We are unable to quantify that
cost at this time.
Unless otherwise indicated, the
numbers in the following tables are
rounded to three significant digits.
1. Industry
The table below lists ONRR’s itemized
low, mid-range, and high estimates of
the costs and benefits that industry
would incur in the first year. Industry
would receive these benefits in the same
amount each year thereafter.
SUMMARY OF ROYALTY IMPACTS TO INDUSTRY
Rule provision
Low
Mid
High
Gas—restore benchmarks:
Remove affiliate resale .........................................................................................................
Remove index .......................................................................................................................
NGLs—restore benchmarks:
Remove affiliate resale .........................................................................................................
Remove index .......................................................................................................................
Gas transportation 50 percent limitation exceptions reinstated ..................................................
Processing allowance 662⁄3 percent limitation exceptions reinstated .........................................
POP contracts processing allowance exceptions of 662⁄3 percent reinstated ............................
Extraordinary processing allowance reinstated ...........................................................................
Deep-water-gathering reinstated .................................................................................................
Oil transportation 50 percent limitation exceptions reinstated ....................................................
Oil and gas line losses allowance reinstated ..............................................................................
BBB bond rate change removed .................................................................................................
Coal—non-arm’s-length netback reinstated ................................................................................
Removing index option administrative costs ...............................................................................
Removing deep-water-gathering administrative costs ................................................................
$0
10,600,000
$1,360,000
10,600,000
$2,710,000
10,600,000
0
(2,210,000)
87,000
42,700
9,470,000
14,200,000
23,900,000
0
3,140,000
5,740,000
(1,030,000)
(303,000)
(3,560,000)
754,000
(2,210,000)
87,000
42,700
9,470,000
14,200,000
28,100,000
0
3,140,000
5,740,000
0
(303,000)
(3,560,000)
1,510,000
(2,210,000)
87,000
42,700
9,470,000
14,200,000
32,300,000
0
3,140,000
5,740,000
1,030,000
(303,000)
(3,560,000)
Total ......................................................................................................................................
60,100,000
67,400,000
74,800,000
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Note: totals from this table and others in this analysis may not add due to rounding.
Benefit—Reinstatement of the Valuation
Benchmarks for Non-Arm’s-Length
Dispositions of Federal Unprocessed
Gas, Residue Gas, and Coalbed Methane
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, and 39, respectively) for
calendar year 2015. We did not include
2016 in any of our data sets because
lessees are still adjusting their reports
for that year and the reported data is
still going through ONRR’s edits.
We then extracted gas royalty data for
non-arm’s-length transactions reported
with the sales type code NARM. We also
extracted gas royalty data for sales type
code POOL because royalty reporters
may also use this code to report certain
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non-arm’s-length transactions. Based on
our experience with auditing
transactions that use sales type code
POOL, only a relatively small portion of
transactions are non-arm’s-length.
Therefore, we used 10 percent of the
POOL volumes in our economic
analysis of the volumes of gas sold at
non-arm’s length.
Based on our experience auditing
production sold under non-arm’s-length
contracts, we find that industry would
incur a royalty decrease between $0.00
and $0.05 per MMBtu under our
proposal to use the benchmarks instead
of the affiliate’s first arm’s-length resale
to value gas production for royalty
purposes. We address the royalty impact
of the index-based option below.
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We generated a range of potential
royalty decreases by assuming no
change in royalties for the low estimate,
$0.025 per MMBtu for the mid-range
estimate, and $0.05 per MMBtu for the
high estimate. We then multiplied the
NARM volume and 10 percent of the
POOL volume reported to ONRR in
2015 by the potential royalty decrease.
The results below are an estimated
benefit to industry due to an annual
royalty decrease of between zero and
approximately $5.4 million. We reduced
this estimate by one-half and assumed
the mid-point of $0.025 totaling $1.36
million. This assumes that 50 percent of
the lessees selling production under
non-arm’s-length arrangements would
have chosen this option under the 2017
Valuation Rule.
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36945
Royalty decrease
($)
2015 MMBtu
volume
(non-rounded)
Low
($0.00)
Mid
($0.025)
High
($0.05)
NARM volume ............................................................................................
10% POOL volume ....................................................................................
97,869,053
10,614,876
$0
0
$2,446,726
265,372
$4,893,453
530,744
Total ....................................................................................................
108,483,929
0
2,712,098
5,424,196
50% of lessees choose this option ............................................................
..............................
0
1,360,000
2,710,000
Benefit—Termination of the IndexBased Option To Value Non-Arm’sLength Sales of Federal Unprocessed
Gas, Residue Gas, and Coalbed Methane
To estimate the royalty impact of
removing 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 seven major geographic areas
with active index prices: The Green
River Basin, San Juan Basin, Piceance
and Uinta Basins, Powder River Basin,
Wind River Basin, Permian Basin, and
Offshore Gulf of Mexico (GOM). These
areas account for approximately 95
percent of all Federal gas produced. To
calculate the estimated impact, we
performed the following steps: First,
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. Second, we subtracted the
transportation deduction that we
specified in the 2017 Valuation Rule
from the highest index price that we
identified in the first step. Third, we
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 the second step. Fourth,
we then multiplied the royalty volume
by the monthly difference that we
calculated in the third step to calculate
a monthly royalty difference for each
region. And fifth, we totaled the
difference that we calculated in the
fourth step for the regions.
In 2015, the estimated royalties due
using the index-based option was
greater than the reported royalties in
every month during our analysis.
We estimate the benefit to industry
due to this change to be a decrease in
royalty payments of approximately
$10.6 million annually. This estimate
represents an average decrease of
approximately 9.8 percent, or $0.026 per
MMBtu, based on an annual royalty
volume of 154,104,793 MMBtu (for
NARM and 10 percent POOL reported
sales type codes). This would have been
the first time that we offered this option;
therefore, we did not know how many
payors would choose it. We reduced
this estimate by one-half, assuming that
50 percent of lessees with non-arm’slength sales would have chosen this
option.
GOM gas
2015 royalties ..............................................................................................................................
Royalty under index option ..........................................................................................................
Difference .....................................................................................................................................
Per unit change ($/MMBtu) .........................................................................................................
% Change ....................................................................................................................................
50% of lessees choose this option ..............................................................................................
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Benefit—Reinstatement of the Valuation
Benchmarks for Non-Arm’s-Length
Dispositions of Federal NGLs
Like the valuation changes that we
discussed previously, for Federal
unprocessed, residue, and coalbed
methane gas valuation, this rule will
value processed Federal NGLs under the
prior valuation benchmarks rather than
either (1) tracing the first arm’s-length
sale or (2) using the index-based option
discussed previously. Lessees will no
longer have the option to value royalties
using an index price value derived from
an NGL commercial price bulletin less
a theoretical processing allowance that
included theoretical transportation and
fractionation of the NGLs. We again
used the 2015 NARM and POOL NGL
data that lessees reported to ONRR for
this analysis.
We performed the same analysis for
valuation using the first arm’s-length
sale for Federal unprocessed, residue,
and coalbed methane gas, as we
discussed. We identified the non-arm’slength volumes that would qualify for
this option (for NARM and 10 percent
POOL reported sales type codes) and
2015 gallons
(rounded to
the
nearest gallon)
NARM volume ..................................................................................................
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Other gas
$72,216,537
79,359,207
7,142,670
0.030
9.9%
........................
$143,618,273
157,684,860
14,066,587
0.025
9.8%
........................
$215,834,810
237,044,067
21,209,257
0.026
9.8%
10,600,000
estimated a cents-per-gallon royalty
decrease. Based on our experience, we
estimate that the NGL resale margin,
similar to gas, would range from zero to
$0.03 per gallon. Thus, our estimated
royalty decrease is zero for the low,
$0.015 per gallon for the mid-range, and
$0.03 per gallon for the high range. The
results below show a mid-range
decrease of $754,000 in royalty
obligations using these assumptions,
and, again, we reduced them by one-half
under the assumption that 50 percent of
lessees would have chosen this option.
Royalty decrease ($)
Low
($0.00 cents)
66,911,096
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Total
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$0
07AUR3
Mid
($0.15)
High
($0.03)
$1,003,666
$2,007,333
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2015 gallons
(rounded to
the
nearest gallon)
Royalty decrease ($)
Low
($0.00 cents)
Mid
($0.15)
High
($0.03)
10% of POOL volume ......................................................................................
33,675,717
0
505,136
1,010,272
Total ..........................................................................................................
100,586,813
0
1,508,802
3,017,604
50% of lessees choose this option ..................................................................
........................
0
754,000
1,510,000
Cost—Termination of the Index-Based
Option To Value Non-Arm’s-Length
Dispositions of Federal NGLs
for all NGLs and the bulletins price each
NGL product (such as ethane and
propane) separately. Therefore, we
calculated a weighted price, or basket
price, from the published prices based
on typical NGL product volumes, as
well as based our analysis on the royalty
changes that result from removal of the
theoretical processing allowance
provided under this option.
theoretical processing allowance that
includes transportation and
fractionation. We used the same 2015
NARM and POOL transaction data for
NGLs for this analysis. We were unable
to compare NGL prices reported on the
form ONRR–2014 to those in
commercial price bulletins because the
prices that lessees report on the form
ONRR–2014 are a single rolled-up price
Like the Federal unprocessed,
residue, and coalbed methane gas
changes that we discussed, lessees will
no longer have the option to pay
royalties on Federal NGLs production
using an index-based value, less a
%
GOM NGLs
$22,292,763
$20,165,669
($2,127,095)
($0.004)
¥9.5%
........................
2015 royalties ..............................................................................................................................
Royalty under index option ..........................................................................................................
Difference .....................................................................................................................................
Per-unit change ($/gal) ................................................................................................................
Percent change ............................................................................................................................
50% of lessees choose this option ..............................................................................................
Cost—Termination of the Index-Based
Option To Value Non-Arm’s-Length
Federal Unprocessed Gas, Residue Gas,
Coalbed Methane, and NGLs
ONRR expects that industry will incur
additional administrative costs from
losing the option to use the index-based
option to value non-arm’s-length
dispositions of Federal unprocessed gas,
residue gas, coalbed methane, and
NGLs. Lessees will have to calculate the
value of their production using the
valuation benchmarks, increasing the
time that it takes to calculate the correct
price. Lessees will also have to calculate
their specific transportation rate for gas,
and processing allowance for NGLs,
rather than using the ONRR-specified
theoretical values.
For the 50 percent of lessees that we
estimated would use this option, we
estimate that eliminating the indexbased option will increase 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. In
2015, ONRR received approximately 16
percent more lines than from the data
used in the prior rule. We used tables
Other NGLs
$9,884,982
$7,585,605
($2,299,378)
($0.008)
¥23.3%
........................
Total
$32,177,746
$27,751,273
($4,426,472)
($0.006)
¥13.8%
($2,210,000)
from the Bureau of Labor Statistics
(BLS) (https://www.bls.gov/oes/current/
oes132011.htm#nat), which we updated
to use current BLS data 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
$53.42 per hour = $38.16 [mean hourly
wage] × 1.4 [benefits cost factor]. Using
a labor cost factor of $53.42 per hour,
we estimate that the annual
administrative cost to industry will be
approximately $303,000.
Estimated
lines
reported using
index option
(50%)
Electronic reporting (99%) .....................................................................................................
Manual reporting (1%) ...........................................................................................................
Industry labor cost/hour .........................................................................................................
1.5
3.5
..............................
221,780
2,240
........................
5,544
131
$53.42
Total cost to industry ......................................................................................................
mstockstill on DSK30JT082PROD with RULES3
Time burden
per line
reported
(min)
..............................
........................
$303,000
Benefit—Allow Transportation
Allowances in Excess of 50 Percent of
the Value of Federal Gas
Prior to the 2017 Valuation Rule, the
Federal gas valuation regulations
limited lessees’ transportation
allowances to 50 percent of the value of
the gas unless they requested and
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20:24 Aug 04, 2017
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received approval to exceed that limit.
The 2017 Valuation Rule eliminated the
lessees’ ability to exceed that limit. This
rule reinstates the lessees’ ability to
request and receive approval to exceed
the 50 percent limitation. To estimate
the impacts associated with this change,
we first identified all calendar year 2015
PO 00000
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Fmt 4701
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Annual
burden
hours
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 benefit to industry
of $87,000.
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Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations
Benefit—Allow Transportation
Allowances in Excess of 50 Percent of
the Value of Federal Oil
Prior to the 2017 Valuation Rule, the
Federal oil valuation regulations limited
lessees’ transportation allowances to 50
percent of the value of the oil unless
they requested and received approval to
exceed that limit. The 2017 Valuation
Rule eliminated the lessees’ ability to
exceed that limit. This rule reinstates
the lessees’ ability to request and
receive approval to exceed the 50percent limitation. To estimate the costs
associated with this change, we
searched for calendar year 2015reported oil transportation allowance
rates that exceeded the 50-percent limit.
We did not find any lines for oil
transportation that exceeded the 50
percent, so there will be no impact to
industry. But companies may exceed the
50-percent limit in the future.
662⁄3-percent limit and totaled that value
to estimate the economic impact of this
provision. The result was an annual
estimated benefit to industry of $42,700.
Benefit—Arm’s-Length POP Contracts
Not Subject to the 662⁄3 Percent
Processing Allowance Limit for Federal
Gas
In this rule and the rule in effect prior
to the 2017 Valuation Rule, lessees with
POP contracts paid royalties based on
their gross proceeds as long as they paid
a minimum value equal to 100 percent
of the value of the residue gas. Under
the 2017 Valuation Rule, we do not
allow lessees with POP contracts to
deduct more than the 662⁄3 percent of
the value of the NGLs. This rule
reinstates the previous regulation’s
provision allowing lessees with POP
contracts to pay royalties based on their
gross proceeds, as long as those gross
proceeds are, at a minimum, equal to
Benefit—Allow Processing Allowances
100 percent of the value of the residue
in Excess of 662⁄3 Percent of the Value
gas. For example, a lessee with a 70of the NGLs for Federal Gas
percent POP contract receives 70
percent of the value of the residue gas
Prior to the 2017 Valuation Rule, the
and 70 percent of the value of the NGLs.
Federal gas valuation regulations
The 30 percent of each product that the
limited lessees’ processing allowances
to 662⁄3 percent of the value of the NGLs lessee gives up to the processing plant
in the past could not, when combined,
unless they requested and received
exceed an equivalent value of 100
approval to exceed that limit. The 2017
percent of the NGLs’ value. By repealing
Valuation Rule eliminated lessees’
ability to exceed that limit. This rule
the 2017 Valuation Rule, the combined
reinstates the lessees’ ability to request
value of each product that the lessee
and receive approval to exceed the 662⁄3- gives up to the processing plant could,
percent limitation. To estimate the cost
again, potentially exceed two-thirds of
to industry associated with this change, the NGLs’ value.
Lessees report POP contracts to ONRR
we first identified all calendar year
using sales type codes APOP for arm’s2015-reported processing allowances
length POP contracts and NPOP for nongreater than 662⁄3 percent. We then
arm’s-length POP contracts. Because
adjusted those allowances down to the
36947
lessees report arm’s-length POP contract
sales as unprocessed gas, there are no
reported processing allowances for us to
analyze, and we cannot determine the
breakout between residue gas and NGLs.
Lessees do report residue gas and NGLs
separately for non-arm’s-length POP
contracts. However, these reported
volumes constitute only 0.07 percent of
all the natural gas royalty volumes
reported to ONRR. We deemed the nonarm’s-length POP volume to be too low
to adequately assess the impact of this
provision on both arm’s-length POP and
non-arm’s-length POP contracts.
Therefore, we examined all reported
calendar year 2015 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 NGL 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 2015 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 many POP
contracts. We calculated 30 percent of
both the value of residue gas and the
NGLs to approximate a theoretical 30percent processing deduction. We then
compared the 30-percent total of residue
gas and NGLs values to 662⁄3 percent of
the NGLs value (the maximum
allowance under the 2017 Valuation
Rule). The table below summarizes
these calculations, which we rounded to
the nearest dollar:
2015 royalty
value prior to
allowances
70%
30%
$494,401,673
132,618,537
$346,081,171
92,832,976
$148,320,502
39,785,561
Total ........................................................................................................
627,020,209
438,914,147
188,106,063
66.67% limit ...................................................................................................
Difference .......................................................................................................
mstockstill on DSK30JT082PROD with RULES3
Residue gas ...................................................................................................
NGLs ..............................................................................................................
88,412,358
99,693,705
(132,618,537 × 2⁄3)
($188,106,063 ¥ $88,412,357)
Our analysis shows that the
theoretical processing deduction for 30
percent of the value of residue gas and
NGLs ($188 million) under our assumed
onshore POP contract allowance would
exceed the 662⁄3 cap ($88 million) under
this rule.
In our analysis for the 2017 Valuation
Rule, the theoretical deduction did not
exceed the allowance cap, and we
estimated that this change would result
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20:24 Aug 04, 2017
Jkt 241001
in no impact. The 2015 data, however,
did show that the theoretical deduction
exceeded the allowance cap, and there
will be an economic impact by repealing
the 2017 Valuation Rule. This is
primarily due to the changing price
relationship between gas and NGLs.
We estimated that the benefit to
industry would be $9.47 million by
taking the royalty value that exceeds the
POP contract allowance ($100 million)
PO 00000
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Sfmt 4700
and dividing by the total of non-POP
volume (1,582,143,530 MMBtu) to
calculate a per-MMBtu rate of $0.06. We
then applied the $0.06 rate to the POP
contract total volume of 157,764,948
MMBtu to get the estimated increase of
$9.47 million. For the sake of this
analysis, we assumed that all processing
costs incurred were allowable.
E:\FR\FM\07AUR3.SGM
07AUR3
36948
Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations
2015 MMBtu volume ..................................................................................................................
Rate/MMBtu over limit ...............................................................................................................
POP MMBtu volume ..................................................................................................................
Total impact to industry .............................................................................................................
Benefit— Reinstatement of Policy
Allowing Transportation Allowances for
Deep-Water-Gathering Systems for
Federal Oil and Gas
The deep-water-gathering policy
discussed previously allows companies
to deduct certain expenses for subsea
gathering from their royalty payments,
even though those costs do not meet
ONRR’s definition of transportation.
This rule would result in ONRR
continuing to apply the policy to the
extent that it is consistent with the prior
(and soon-to-be-reinstated) regulations.
Lessees would therefore be allowed to
claim additional allowances, which
would decrease their royalties due. To
analyze the impact to industry of
reinstating this policy, we used data
from BSEE’s ArcGIS TIMS (Technical
Information Management System)
database to estimate that 113 subsea
pipeline segments serving 140 leases
currently qualify for an allowance under
the policy. We assumed all segments
were the same—in other words, we did
not take into account the size, length, or
type of pipeline. For our analysis we
also considered only pipeline segments
that were in active status and leases in
producing status. To determine a range
(shown in the tables below as low, mid,
and high estimates) for the impact for
industry, ONRR estimated a 15 percent
error rate in our identification of the 113
eligible pipeline segments, resulting in
a range of 96 to 130 eligible pipeline
segments.
1,582,143,530
$0.06
157,764,948
$9,470,000
Historical ONRR audit data was
available for 13 subsea gathering
segments, which served 15 leases
covering time periods from 1999
through 2010. We used this data to
determine an average initial amount of
capital investment in pipeline segments.
We used the initial capital investment
amount to calculate depreciation and a
return on undepreciated capital
investment (ROI) for the eligible
pipeline segments. We calculated
depreciation using a straight-line
depreciation schedule based on a 20year 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 at the time we performed this
analysis. We based the calculations for
depreciation and ROI on the first year a
pipeline was in service.
From the same audit data, we
calculated an average annual operating
and maintenance (O&M) cost. We
increased the O&M cost by 12 percent
to account for overhead expenses. Based
on experience and audit data, we
assumed that 12 percent is a reasonable
increase for overhead. We then
decreased the total annual O&M cost per
pipeline segment by nine percent
because an average of nine 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
Gulf of Mexico. Based on the these
($99,693,705/1,582,143,530)
($.06 × 157,764,948)
calculations, the average annual
allowance per pipeline segment is
approximately $226,664. This
represents the estimated amount per
pipeline segment ONRR would no
longer allow lessees to take as a
transportation allowance based on our
rescission of the Deep Water Policy in
this proposed rulemaking.
The total cost to industry would be
the $226,664 annual allowance per
pipeline segment that we would allow
under this proposed rulemaking times
the number of eligible segments. To
calculate a range for this total, we
multiplied the average annual
allowance by the low (96), mid (113),
and high (130) number of eligible
segments. The low, mid, and high
annual allowance estimates we would
allow are $21.8 million, $25.6 million,
and $29.5 million, respectively.
Of the currently eligible leases, 56 out
of 140, or about 40 percent, qualified for
deep water royalty relief under the
policy. However, due to varying lease
terms, royalty relief programs, price
thresholds, volume thresholds,
litigation, and other factors, ONRR
estimated that only one-half of the 56
leases eligible for royalty relief (20
percent of the 56) actually received
royalty relief. Therefore, we decreased
the low, mid, and high estimated annual
benefit to industry by 20 percent. The
table below shows the estimated royalty
impact of this section of the proposed
rule based on the allowances we will
allow under this rule.
Low
Estimated Royalty Impact ............................................................................................................
mstockstill on DSK30JT082PROD with RULES3
Cost—Reinstatement of Policy Allowing
Transportation Allowances for DeepWater- Gathering Systems for Federal
Oil and Gas
We estimate the restoration of
transportation allowances for deepwater-gathering systems would
eliminate the industry administrative
benefit under the 2017 Valuation Rule
as lessees would have to perform this
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20:24 Aug 04, 2017
Jkt 241001
calculation. We assume that the cost to
perform this calculation is significant
because in our experience industry has
often hired outside consultants to
calculate their subsea transportation
allowances. Using this information, we
estimate each company with leases
eligible for transportation allowances for
deep water gathering systems would
allocate one full-time FTE annually to
perform this calculation, whether they
PO 00000
Frm 00016
Fmt 4701
Sfmt 4700
Mid
High
$23,900,000
$28,100,000
$32,300,000
use consultants or perform the
calculation in-house. We used the
Bureau of Labor Statistics to estimate
the hourly cost for industry accountants
in a metropolitan area ($38.16 mean
hourly wage) with a multiplier of 1.4 for
industry benefits to equal approximately
$53.42 per hour ($38.16 × 1.4). Using
this labor cost per hour, we estimate the
annual administrative cost to industry
would be approximately:
E:\FR\FM\07AUR3.SGM
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Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations
36949
Annual
burden
hours per
company
Industry
labor
cost/hour
Companies
reporting
eligible
leases
Estimated
cost to
industry
2,080
$53.42
32
$3,560,000
Deep Water Gathering .....................................................................................
Benefit—Reinstating Extraordinary
Processing Cost Allowances for Federal
Gas
As we discussed previously, we are
reinstating the provision in our
regulations that allows lessees to request
an extraordinary processing cost
allowance and to allow any
extraordinary processing cost
allowances that we previously granted.
We have granted two such approvals in
the past, so we know the lease universe
that is claiming this allowance and were
able to retrieve the processing allowance
data 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 2012 through 2015 for
the leases at issue. We then averaged the
yearly totals for those four years to
estimate an annual benefit to industry of
$14.2 million in decreased royalties.
Benefit—Increasing the Rate of Return
Used To Calculate Non-Arm’s-Length
Transportation Allowances From 1 to
1.3 Times the Standard and Poor’s BBB
Bond for Federal Oil and Gas
mstockstill on DSK30JT082PROD with RULES3
For Federal oil transportation, we do
not maintain or request data identifying
whether transportation allowances are
arm’s length or non-arm’s length.
However, in our experience, lessees
transport a significant portion of Gulf of
Mexico (GOM) oil through their own
pipelines. In addition, many onshore
transportation allowances include costs
of trucking and rail and, most likely,
this change would not impact those.
Therefore, to calculate the costs
associated with this change, we
assumed that 50 percent of the GOM
transportation allowances are non-arm’s
length and that ten 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, onethird depreciation expenses, and onethird operation, maintenance, and
overhead expenses.
In 2015, the total oil transportation
allowances that Federal lessees
deducted were approximately $100
million from the GOM and $12.5
million from everywhere else. Based on
these totals and our assumptions
regarding the makeup of the allowance
components, the portion of the nonarm’s-length allowances attributable to
the rate of return will be approximately
$16,600,000 for the GOM ($100,000,000
× 1⁄3 × 50%) and $416,000 ($12,500,000
× 1⁄3 × 10%) for the rest of the country.
Based on these assumptions, industry
will receive an increase in yearly oil
transportation allowance deductions of
approximately $3,920,000 ($17,000,000
× (1.3 ¥ 1.0)/1.3). That is, we estimate
that the net benefit to industry for oil
transportation allowances as a result of
this change will be an approximately
$3,920,000 in decreased royalties due.
Like Federal oil, we do not maintain
or request information on whether
Federal gas transportation allowances
are arm’s-length or non-arm’s length.
However, unlike Federal oil, in our
experience, it is not common for GOM
gas to be transported through lesseeowned 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 that we made for oil.
In 2015, the total gas transportation
allowances that Federal lessees
deducted were approximately $238
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 $7.93 million
($238,000,000 × 1⁄3 × 10%). Therefore,
industry will see an increase in yearly
gas transportation allowance deductions
of approximately $1.82 million ($7.93
million × (1.3 ¥ 1.0)/1.3). That is, the
net decreased cost to industry for gas
transportation allowances will be
approximately $1,820,000.
The combined impact to industry for
this change will be $5,740,000 in
decreased royalties due.
No Change—Disallow a Rate of Return
on Reasonable Salvage Value for Federal
Oil, Gas, and Coal
In the 2017 Valuation Rule, ONRR
estimated that this provision would
have no impact to industry. ONRR
likewise estimates that the repeal has no
impact.
Benefit—Allow Line Loss as a
Component of Non-Arm’s-Length Oil
and Gas Transportation
This rule also reinstates the regulatory
provision allowing lessees to deduct the
costs of pipeline losses, both actual and
theoretical, when calculating non-arm’slength 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
would also equate 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 2015, the Federal royalty value
subject to transportation allowances was
$2,746,256,148 in the GOM and
$1,039,271,142 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 $2.96
million, as we detailed in the table
below. Therefore, the annual benefit to
industry will be approximately $2.96
million.
OIL LINE LOSS ROYALTY IMPACT
Line loss
%
50% of GOM royalty value ......................................................................................................
10% of everywhere else royalty value ....................................................................................
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$1,373,128,209
103,927,114
E:\FR\FM\07AUR3.SGM
07AUR3
0.2
0.2
Royalty
decrease
$2,750,000
208,000
36950
Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations
OIL LINE LOSS ROYALTY IMPACT—Continued
Line loss
%
Total ..................................................................................................................................
For Federal gas produced in calendar
year 2015, the Federal gas royalty value
subject to transportation allowances was
Royalty
decrease
2,960,000
$888,676,828. 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 and annual benefit
to industry would be $178,000.
GAS LINE LOSS ROYALTY IMPACT
Line loss
%
10% of royalty value ................................................................................................................
The total estimated royalty decrease
for both oil and gas due to this change
will be $3.14 million [$2,960,000 (oil)
plus $178,000 (gas) = $3,140,000].
Benefit—Depreciating Oil Pipeline
Assets Only Once
Under the non-arm’s-length
transportation allowance section of this
rule and the rule in effect prior to the
2017 Valuation Rule, for Federal oil, if
an oil pipeline is sold, the purchasing
company might use the purchase price
to establish a new depreciation
schedule, provided that the purchasing
company is a royalty payor claiming a
non-arm’s-length transportation
allowance. In theory, this change results
in additional royalty savings for
companies. However, based on our
experience monitoring the oil markets,
we find that the sale of oil pipeline
assets is rare. 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
benefit to industry under this rule, we
cannot quantify the cost at this time.
mstockstill on DSK30JT082PROD with RULES3
No Change—Eliminating the Use of the
First Arm’s-Length Sale to Value NonArm’s-Length Sales of Federal Coal and
Sales of Federal Coal Between Parties
That Lack Opposing Economic
Interest—‘‘Coal Cooperatives’’ in the
2017 Valuation Rule
In the 2017 Valuation Rule, ONRR did
not estimate any impacts to industry for
the change in regulations for this
provision. This repeal will reinstate the
valuation regulations as they were prior
to the 2017 Valuation Rule’s
publication. Therefore, ONRR does not
estimate any impact to industry at this
time.
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$88,867,683
No Change—Eliminating the Use of
Arm’s-Length Electricity Sales to Value
Non-Arm’s-Length Dispositions of
Federal Coal and Dispositions of Federal
Coal Parties That Lack Opposing
Economic Interest—‘‘Coal Cooperatives’’
in the 2017 Valuation Rule
In the 2017 Valuation Rule, ONRR did
not estimate any impacts to industry for
the change in regulations for this
provision. This repeal will reinstate the
valuation regulations as they were prior
to the 2017 Valuation Rule’s
publication. Therefore, ONRR does not
estimate any impact to industry at this
time.
No Change—Eliminating the Default
Provision to Value Non-Arm’s-Length
Sales of Federal Coal in Lieu of Sales of
Electricity
For these situations, valuation of
Federal coal will be determined under
the non-arm’s-length benchmarks after
this repeal of the 2017 Valuation Rule.
Because the default provision
establishes a valuation method that
approximates the market value of the
coal very similar to the benchmarks, we
estimate that the royalty effect of this
rule on lessees of Federal coal will be
nominal.
No Change—Using the First Arm’sLength Sale to Value Non-Arm’s-Length
Sales of Indian Coal
In the 2017 Valuation Rule, ONRR did
not estimate any impacts to industry for
the change in regulations for this
provision. This repeal will reinstate the
valuation regulations as they were prior
to the 2017 Valuation Rule’s
publication. Therefore, we do not
estimate any impact to industry at this
time.
PO 00000
Frm 00018
Fmt 4701
Sfmt 4700
Royalty
decrease
0.2
$178,000
No Change—Using Sales of Electricity to
Value Non-Arm’s-Length Sales of Indian
Coal
In the 2017 Valuation Rule, ONRR did
not estimate any impacts to industry for
the change in regulations for this
provision. This repeal will reinstate the
valuation regulations as they were prior
to the 2017 Valuation Rule’s
publication. Therefore, we do not
estimate any impact to industry at this
time.
No Change—Using First Arm’s-Length
Sale to Value Sales of Indian Coal
Between Coal Cooperative Members
In the 2017 Valuation Rule, ONRR did
not estimate any impacts to industry for
the change in regulations for this
provision. This repeal will reinstate the
valuation regulations as they were prior
to the 2017 Valuation Rule’s
publication. Therefore, we do not
estimate any impact to industry at this
time.
No Change—Elimination of the Default
Provision to Value Federal Oil, Gas, and
Coal and Indian Coal
In the 2017 Valuation Rule, we
anticipated that we would have used the
default provision only in specific cases
where conventional valuation
procedures have not worked to establish
a value for royalty purposes. We also
stated that assigning a royalty impact
figure to any of the instances where we
would have used the default provisions
was speculative because (1) each
instance would have been case-specific,
(2) we could not anticipate when we
would have used the option, and (3) we
could not anticipate the value that we
would have required companies to pay.
Additionally, we estimated that the
royalty impact would have been
relatively small because the default
provision would always have
established a reasonable value of
E:\FR\FM\07AUR3.SGM
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Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations
production using market-based
transaction data, which has always been
the basis for our royalty valuation rules.
Therefore, removal of the default
provision will have a similarly small
and speculative royalty difference.
2. State and Local Governments
We estimate that the States and local
governments that this rule impacts will
incur a decrease in royalty receipts. The
details of this impact are outlined
below.
States and local governments
receiving revenues for offshore Outer
Continental Shelf Lands Act Section
8(g) leases will continue to receive
royalties as under the regulations
preceding the 2017 Valuation Rule, as
will States receiving revenues from
onshore Federal lands. Based on the
ratio of Federal revenues disbursed to
States and local governments for section
8(g) leases and the onshore States we
detail in the table below, ONRR
assumed the same proportion of revenue
decreases for each proposal that will
impact those State revenues for most of
the provisions.
36951
royalties as a result of these changes.
The royalty decrease incurred by the
Federal government will be the
difference between the total royalty
OnOffshore
8(g)
shore
decrease to industry and the royalty
%
%
%
decrease affecting the States and local
governments. The net yearly impact on
Federal ..............
50
100
73
State .................
50
0
0 the Federal government will be
Section 8(g) ......
0
0
27 approximately $55.8 million, which we
detail in section (5) below.
Some provisions of this rule affect
5. Summary of Royalty Impacts and
Federal, State, and local government
Costs to Industry, State and Local
revenues, while others, such as
Governments, Indian Lessors, and the
reinstating extraordinary processing cost Federal Government
allowances, affect only onshore States’
In the table below, the negative values
and Federal revenues. The table
in the industry column represent their
summarizing the State and local
estimated royalty collection decrease for
government royalty decreases that we
Federal, State, and local governments,
provide in section 5 details these
while the positive values in the other
differences.
columns represent the increase in
3. Indian Lessors
royalty savings for industry. Please note
that the estimated impacts to Federal,
ONRR estimates that the changes to
the coal regulations that apply to Indian State, and local governments do not
include the administrative savings
lessors will have no impact on their
provisions of the economic analysis
royalties.
discussed above. Those provisions are
4. Federal Government
only realized by industry. For the
The impact to the Federal
purposes of this summary table, we
government, like the States and local
used the midpoint estimates for these
governments, will be a net decrease in
impacts.
ROYALTY DISTRIBUTIONS BY LEASE
TYPE
Rule Provision
Industry
Gas—restore benchmarks:
Remove affiliate Resale ............................................................................
Remove index ...........................................................................................
NGLs—restore benchmarks:
Remove affiliate Resale ............................................................................
Remove index ...........................................................................................
Gas transportation 50% limitation exceptions reinstated ................................
Processing allowance 662⁄3% limitation exceptions reinstated .......................
POP contracts’ processing allowance exceptions of 662⁄3% limitation reinstated ............................................................................................................
Extraordinary processing allowance reinstated ...............................................
Deep-water-gathering reinstated .....................................................................
Oil transportation 50% limitation exceptions reinstated ..................................
Oil and gas line losses allowance reinstated ..................................................
BBB bond rate change removed .....................................................................
Coal provisions ................................................................................................
Total ..........................................................................................................
Federal
State
State 8(g)
$1,360,000
$10,600,000
($865,000)
($6,750,000)
($483,000)
($3,760,000)
($11,600)
($90,600)
$754,000
($2,210,000)
$87,000
$42,700
($529,000)
$1,550,000
($55,400)
($29,900)
($220,000)
$646,000
($30,900)
($12,500)
($4,830)
$14,200
($744)
($274)
$9,470,000
$14,200,000
$28,100,000
$0
$3,140,000
$5,740,000
$0
($6,640,000)
($7,100,000)
($28,100,000)
$0
($2,560,000)
($4,680,000)
$0
($2,770,000)
($7,100,000)
$0
$0
($562,000)
($1,030,000)
$0
($60,700)
$0
$0
$0
($17,200)
($31,500)
$0
$71,300,000
($55,800,000)
($15,300,000)
($200,000)
Note: totals from this table and others in this analysis may not add due to rounding.
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B. Regulatory Planning and Review
(Executive Orders 12866 and 13563 and
Executive Order 13771 on Reducing
Regulation and Controlling Regulatory
Costs Dated January 30, 2017)
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 rules. OIRA has
determined that this rule is significant
because it may materially alter the
budgetary impact of entitlements,
grants, user fees, or loan programs or the
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rights and obligations of recipients
thereof.
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,
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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.
This final rule is considered a
deregulatory action under E.O. 13771,
Reducing Regulation and Controlling
Regulatory Costs (82 FR 9339, Feb. 3,
2017). Although there are some costs to
industry associated with this rule, the
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rule still results in an overall savings to
industry. Details on the estimated
savings and costs associated with the
rule can be found in the rule’s economic
analysis.
C. Regulatory Flexibility Act
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The Department of the Interior
(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 the 2017
Valuation Rule, Procedural Matters,
item 1, starting at 81 FR 43359, and item
3, starting at 81 FR 43367.
This rule will affect only lessees
under Federal oil and gas leases and
Federal and Indian coal leases.
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 2015
sales data, this rule is a benefit to
industry of approximately $71 million
dollars per year. Small businesses
accounted for about 20 percent of the
royalties paid in 2015. Applying that
percentage to industry costs, we
estimate that this final rule will benefit
all small-business lessors approximately
$14,200,000 per year. The amount will
vary for each company depending on
the volume of production that each
small business produces and sells each
year.
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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 benefit
affected small businesses a collective
total of $14,200,000 per year.
D. 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:
(1) Does not have an annual effect on
the economy of $100 million or more.
We estimate that industry will annually
benefit between $60,100,000 and
$74,800,000. These figures are a reversal
of the impacts described in the 2017
Valuation Rule, under Procedural
Matters, item 1, starting at 81 FR 43359,
and item 4, 81 FR 43368, but has been
adjusted to include more current data.
Therefore, the economic impact on
industry, State and local governments
and the Federal government will be
below the $100 million threshold that
the Federal government uses to define a
rule as having a significant impact on
the economy.
(2) Will not cause a major increase in
costs or prices for consumers;
individual industries; Federal, State, or
local government agencies; or
geographic regions. See Procedural
Matters, item 1.
(3) 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.
This rule will benefit U.S.-based
enterprises.
E. 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.
Therefore, 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. See Procedural Matters,
item 1.
F. 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
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does not require a Takings Implication
Assessment.
G. 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 assessment.
The management of Federal oil and gas
leases, and Federal and Indian coal
leases is the responsibility of the
Secretary of the Interior. 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.
H. Civil Justice Reform (E.O. 12988)
This rule complies with the
requirements of E.O. 12988.
Specifically, this rule:
(a) Meets the criteria of § 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 § 3(b)(2),
which requires that we write all
regulations in clear language using clear
legal standards.
I. Consultation With Indian Tribes (E.O.
13175 and Departmental Policy)
The Department strives to strengthen
its government-to-government
relationship with Indian Tribes through
a commitment to consultation with
Indian Tribes and recognition of their
right to self-governance and Tribal
sovereignty. Under the criteria in E.O.
13175, we evaluated this final rule and
determined that it will have no potential
effects on Federally-recognized Indian
Tribes. Specifically, we determined that
this rule will restore the historical
valuation methodology for coal
produced from Indian leases.
Accordingly:
(1) We mailed letters, on April 3,
2017, to the Crow Tribe of Montana,
Hopi Tribe of Arizona, and Navajo
Nation to consult with the Tribes on
both the Notice of Proposed Rulemaking
and Advance Notice of Proposed
Rulemaking for the proposed repeal of
2017 Indian coal valuation regulations.
(2) We consulted with the Navajo
Nation on May 24, 2017, in Window
Rock, Arizona.
(3) We consulted with the Crow Tribe
on May 26, 2017, in Crow Agency,
Montana.
(4) We consulted with the Hopi on
June 21, 2017, in Kykotsmovi, Arizona.
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J. Paperwork Reduction Act
This rule:
(1) Does not contain any new
information collection requirements.
(2) Does not require a submission to
the OMB under the Paperwork
Reduction Act of 1995 (44 U.S.C. 3501
et seq.). See 5 CFR 1320.4(a)(2).
This rule will leave intact the
information collection requirements that
OMB already approved under OMB
Control Numbers 1012–0004, 1012–
0005, and 1012–0010.
K. 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(i) in that this is ‘‘. . . of an
administrative, financial, legal,
technical, or procedural nature. . . .’’
This rule also qualifies for categorically
exclusion under Departmental Manual,
part 516, section 15.4.(C)(1) in that its
impacts are limited to administrative,
economic, or technological effects. 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 the repeal of the 2017 Valuation
Rule will have no consequence on the
physical environment. This rule does
not alter, in any material way, natural
resources exploration, production, or
transportation.
L. 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
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30 CFR Part 1202
Coal, Continental shelf, Government
contracts, Indian lands, Mineral
royalties, Natural gas, Oil and gas
exploration, Public lands—mineral
resources, Reporting and recordkeeping
requirements.
30 CFR Part 1206
Coal, Continental shelf, Government
contracts, Indian lands, Mineral
royalties, Oil and gas exploration,
Public lands—mineral resources,
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Reporting and recordkeeping
requirements.
Gregory J. Gould,
Director for Office of Natural Resources
Revenue.
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
1. The authority citation for part 1202
continues to read as follows:
■
Authority: 5 U.S.C. 301 et seq., 25 U.S.C.
396 et seq., 396a et seq., 2101 et seq.; 30
U.S.C. 181 et seq., 351 et seq., 1001 et seq.,
1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301
et seq.,1331 et seq., and 1801 et seq.
Subpart B—Oil, Gas, and OCS Sulfur,
General
2. In § 1202.51, revise paragraph (b) to
read as follows:
■
§ 1202.51
Scope and definitions.
*
*
*
*
*
(b) The definitions in subparts B, C,
D, and E of part 1206 of this title are
applicable to subparts B, C, D, and J of
this part.
Subpart F—Coal
■
3. Remove § 1202.251.
PART 1206—PRODUCT VALUATION
4. The authority citation for part 1206
continues to read as follows:
■
Authority: 5 U.S.C. 301 et seq., 25 U.S.C.
396 et seq., 396a et seq., 2101 et seq.; 30
U.S.C. 181 et seq., 351 et seq., 1001 et seq.,
1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301
et seq., 1331 et seq., and 1801 et seq.
5. Revise subpart A, consisting of
§ 1206.10, to read as follows:
■
Subpart A—General Provisions and
Definitions
§ 1206.10
Information collection.
The information collection
requirements contained in this part have
been approved by the Office of
Management and Budget (OMB) under
44 U.S.C. 3501 et seq. The forms, filing
date, and approved OMB clearance
numbers are identified in § 1210.10.
■ 6. Revise subpart C to read as follows:
Subpart C—Federal Oil
Sec.
1206.100 What is the purpose of this
subpart?
1206.101 What definitions apply to this
subpart?
1206.102 How do I calculate royalty value
for oil that I or my affiliate sell(s) under
an arm’s-length contract?
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36953
1206.103 How do I value oil that is not sold
under an arm’s-length contract?
1206.104 What publications are acceptable
to ONRR?
1206.105 What records must I keep to
support my calculations of value under
this subpart?
1206.106 What are my responsibilities to
place production into marketable
condition and to market production?
1206.107 How do I request a value
determination?
1206.108 Does ONRR protect information I
provide?
1206.109 When may I take a transportation
allowance in determining value?
1206.110 How do I determine a
transportation allowance under an arm’slength transportation contract?
1206.111 How do I determine a
transportation allowance if I do not have
an arm’s-length transportation contract
or arm’s-length tariff?
1206.112 What adjustments and
transportation allowances apply when I
value oil production from my lease using
NYMEX prices or ANS spot prices?
1206.113 How will ONRR identify market
centers?
1206.114 What are my reporting
requirements under an arm’s-length
transportation contract?
1206.115 What are my reporting
requirements under a non-arm’s-length
transportation arrangement?
1206.116 What interest applies if I
improperly report a transportation
allowance?
1206.117 What reporting adjustments must
I make for transportation allowances?
1206.119 How are the royalty quantity and
quality determined?
1206.120 How are operating allowances
determined?
Subpart C—Federal Oil
§ 1206.100
subpart?
What is the purpose of this
(a) This subpart applies to all oil
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 the 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
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must determine and report royalty value
for the lessee’s oil by applying the rules
in this subpart to the lessee’s
disposition of its oil.
(d) If the regulations in this subpart
are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between
the United States and a lessee resulting
from administrative or judicial
litigation;
(3) A written agreement between the
lessee and the ONRR Director
establishing a method to determine the
value of production from any lease that
ONRR expects at least would
approximate the value established
under this subpart; or
(4) An express provision of an oil and
gas lease subject to this subpart, then
the statute, settlement agreement,
written agreement, or lease provision
will govern to the extent of the
inconsistency.
(e) ONRR may audit and adjust all
royalty payments.
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§ 1206.101
subpart?
What definitions apply to this
The following definitions apply to
this subpart:
Affiliate means a person who
controls, is controlled by, or is under
common control with another person.
For purposes of this subpart:
(1) Ownership or common ownership
of more than 50 percent of the voting
securities, or instruments of ownership,
or other forms of ownership, of another
person constitutes control. Ownership
of less than 10 percent constitutes a
presumption of noncontrol that ONRR
may rebut.
(2) If there is ownership or common
ownership of 10 through 50 percent of
the voting securities or instruments of
ownership, or other forms of ownership,
of another person, ONRR will consider
the following factors in determining
whether 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, whether a
person is the greatest single owner, or
whether there is an opposing voting
bloc of greater ownership;
(iii) Operation of a lease, plant, or
other facility;
(iv) The extent of participation by
other owners in operations and day-today management of a lease, plant, or
other facility; and
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(v) Other evidence of power to
exercise control over or common control
with another person.
(3) Regardless of any percentage of
ownership or common ownership,
relatives, either by blood or marriage,
are affiliates.
ANS means Alaska North Slope
(ANS).
Area means a geographic region at
least as large as the limits of an oil field,
in which oil has similar quality,
economic, and legal characteristics.
Arm’s-length contract means a
contract or agreement between
independent persons who are not
affiliates and who have opposing
economic interests regarding that
contract. To be considered arm’s length
for any production month, a contract
must satisfy this definition for that
month, as well as when the contract was
executed.
Audit means a review, conducted
under generally accepted accounting
and auditing standards, of royalty
payment compliance activities of
lessees, designees or other persons who
pay royalties, rents, or bonuses on
Federal leases.
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.
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.
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 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
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two separate sales within the same
agreement. Examples of other types of
exchange agreements include, but are
not limited to, exchanges of produced
oil for specific types of crude oil (e.g.,
West Texas Intermediate); exchanges of
produced oil for other crude oil at other
locations (Location Trades); exchanges
of produced oil for other grades of oil
(Grade Trades); and multi-party
exchanges.
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.
Gathering means the movement of
lease production to a central
accumulation or treatment point on the
lease, unit, or communitized area, or to
a central accumulation or treatment
point off the lease, unit, or
communitized area that BLM or BSEE
approves for onshore and offshore
leases, respectively.
Gross proceeds means the total
monies and other consideration
accruing for the disposition of oil
produced. Gross proceeds also include,
but are not limited to, the following
examples:
(1) Payments for services such as
dehydration, marketing, measurement,
or gathering which the lessee must
perform at no cost to the Federal
Government;
(2) The value of services, such as salt
water disposal, that the producer
normally performs but that the buyer
performs on the producer’s behalf;
(3) Reimbursements for harboring or
terminaling fees;
(4) Tax reimbursements, even though
the Federal royalty interest may be
exempt from taxation;
(5) Payments made to reduce or buy
down the purchase price of oil to be
produced in later periods, by allocating
such payments over the production
whose price the payment reduces and
including the allocated amounts as
proceeds for the production as it occurs;
and
(6) Monies and all other consideration
to which a seller is contractually or
legally entitled, but does not seek to
collect through reasonable efforts.
Lease means any contract, profit-share
arrangement, joint venture, or other
agreement issued or approved by the
United States under a mineral leasing
law that authorizes exploration for,
development or extraction of, or
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removal of oil or gas—or the land area
covered by that authorization,
whichever the context requires.
Lessee means any person to whom the
United States issues an oil and gas lease,
an assignee of all or a part of the record
title interest, or any person to whom
operating rights in a lease have been
assigned.
Location differential means an
amount paid or received (whether in
money or in barrels of oil) under an
exchange agreement that results from
differences in location between oil
delivered in exchange and oil received
in the exchange. A location differential
may represent all or part of the
difference between the price received
for oil delivered and the price paid for
oil received under a buy/sell exchange
agreement.
Market center means a major point
ONRR recognizes for oil sales, refining,
or transshipment. Market centers
generally are locations where ONRRapproved publications publish oil spot
prices.
Marketable condition means oil
sufficiently free from impurities and
otherwise in a condition a purchaser
will accept under a sales contract
typical for the field or area.
Netting means reducing the reported
sales value to account for transportation
instead of reporting a transportation
allowance as a separate entry on form
ONRR–2014.
NYMEX price means the average of
the New York Mercantile Exchange
(NYMEX) settlement prices for light
sweet crude oil delivered at Cushing,
Oklahoma, calculated as follows:
(1) Sum the prices published for each
day during the calendar month of
production (excluding weekends and
holidays) for oil to be delivered in the
prompt month corresponding to each
such day; and
(2) Divide the sum by the number of
days on which those prices are
published (excluding weekends and
holidays).
Oil means a mixture of hydrocarbons
that existed in the liquid phase in
natural underground reservoirs, remains
liquid at atmospheric pressure after
passing through surface separating
facilities, and is marketed or used as a
liquid. Condensate recovered in lease
separators or field facilities is oil.
ONRR-approved publication means a
publication ONRR approves for
determining ANS spot prices or WTI
differentials.
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
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U.S.C. 1301) and of which the subsoil
and seabed appertain to the United
States and are subject to its jurisdiction
and control.
Person means any individual, firm,
corporation, association, partnership,
consortium, or joint venture (when
established as a separate entity).
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.
Rocky Mountain Region means the
States of Colorado, Montana, North
Dakota, South Dakota, Utah, and
Wyoming, except for those portions of
the San Juan Basin and other oilproducing fields in the ‘‘Four Corners’’
area that lie within Colorado and Utah.
Roll means an adjustment to the
NYMEX price that is calculated as
follows: Roll = .6667 × (P0 ¥ P1) + .3333
× (P0 ¥ P2), where: P0 = the average of
the daily NYMEX settlement prices for
deliveries during the prompt month that
is the same as the month of production,
as published for each day during the
trading month for which the month of
production is the prompt month; P1 =
the average of the daily NYMEX
settlement prices for deliveries during
the month following the month of
production, published for each day
during the trading month for which the
month of production is the prompt
month; and P2 = the average of the daily
NYMEX settlement prices for deliveries
during the second month following the
month of production, as published for
each day during the trading month for
which the month of production is the
prompt month. Calculate the average of
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 March.
March was the prompt month (for year
2003) from January 22 through February
20. April was the first month following
the month of production, and May was
the second month following the month
of production. P0 therefore is the
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average of the daily NYMEX settlement
prices for deliveries during March
published for each business day
between January 22 and February 20. P1
is the average of the daily NYMEX
settlement prices for deliveries during
April published for each business day
between January 22 and February 20. P2
is the average of the daily NYMEX
settlement prices for deliveries during
May published for each business day
between January 22 and February 20. In
this example, assume that P0 = $28.00
per bbl, P1 = $27.70 per bbl, and P2 =
$27.10 per bbl. In this example (a
declining market), Roll = .6667 ×
($28.00 ¥ $27.70) + .3333 × ($28.00 ¥
$27.10) = $.20 + $.30 = $.50. 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 July. July
2003 was the prompt month from May
21 through June 20. August was the first
month following the month of
production, and September was the
second month following the month of
production. P0 therefore is the average
of the daily NYMEX settlement prices
for deliveries during July published for
each business day between May 21 and
June 20. P1 is the average of the daily
NYMEX settlement prices for deliveries
during August published for each
business day between May 21 and June
20. P2 is the average of the daily
NYMEX settlement prices for deliveries
during September published for each
business day between May 21 and June
20. In this example, assume that P0 =
$28.00 per bbl, P1 = $28.90 per bbl, and
P2 = $29.50 per bbl. In this example (a
rising market), Roll = .6667 ×
($28.00¥$28.90) + .3333 × ($28.00 ¥
$29.50) = (¥$.60) + (¥$.50) = ¥$1.10.
You add this negative number to the
NYMEX price (effectively a subtraction
from the NYMEX price).
Sale means a contract between two
persons where:
(1) The seller unconditionally
transfers title to the oil to the buyer and
does not retain any related rights such
as the right to buy back similar
quantities of oil from the buyer
elsewhere;
(2) The buyer pays money or other
consideration for the oil; and
(3) The parties’ intent is for a sale of
the oil to occur.
Spot price means the price under a
spot sales contract where:
(1) A seller agrees to sell to a buyer
a specified amount of oil at a specified
price over a specified period of short
duration;
(2) No cancellation notice is required
to terminate the sales agreement; and
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(3) There is no obligation or implied
intent to continue to sell in subsequent
periods.
Tendering program means a
producer’s offer of a portion of its crude
oil produced from a field or area for
competitive bidding, regardless of
whether the production is offered or
sold at or near the lease or unit or away
from the lease or unit.
Trading month means the period
extending from the second business day
before the 25th day of the second
calendar month preceding the delivery
month (or, if the 25th day of that month
is a non-business day, the second
business day before the last business
day preceding the 25th day of that
month) through the third business day
before the 25th day of the calendar
month preceding the delivery month
(or, if the 25th day of that month is a
non-business day, the third business
day before the last business day
preceding the 25th day of that month),
unless the NYMEX publishes a different
definition or different dates on its
official Web site, www.nymex.com, in
which case the NYMEX definition will
apply.
Transportation allowance means a
deduction in determining royalty value
for the reasonable, actual costs of
moving oil to a point of sale or delivery
off the lease, unit area, or communitized
area. The transportation allowance does
not include gathering costs.
WTI 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.
(1) Example. Assume the production
month was March 2003. Industry trade
publications performed their price
surveys and determined differentials
during January 26 through February 25
for oil delivered in March. The WTI
differential (for example, the West Texas
Sour crude at Midland, Texas, spread
versus WTI) applicable to valuing oil
produced in the March 2003 production
month would be determined using all
the business days for which differentials
were published during the period
January 26 through February 25
excluding weekends and holidays (22
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days). To calculate the WTI differential,
add together all of the daily mean
differentials published for January 26
through February 25 and divide that
sum by 22.
(2) [Reserved]
§ 1206.102 How do I calculate royalty
value for oil that I or my affiliate sell(s)
under an arm’s-length contract?
(a) The value of oil under this section
is the gross proceeds accruing to the
seller under the arm’s-length contract,
less applicable allowances determined
under § 1206.110 or § 1206.111. This
value does not apply if you exercise an
option to use a different value provided
in paragraph (d)(1) or (d)(2)(i) of this
section, or if one of the exceptions in
paragraph (c) of this section applies. Use
this paragraph (a) to value oil that:
(1) You sell under an arm’s-length
sales contract; or
(2) You sell or transfer to your affiliate
or another person under a non-arm’slength contract and that affiliate or
person, or another affiliate of either of
them, then sells the oil under an arm’slength contract, unless you exercise the
option provided in paragraph (d)(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) This paragraph contains
exceptions to the valuation rule in
paragraph (a) of this section. Apply
these exceptions on an individual
contract basis.
(1) In conducting reviews and audits,
if ONRR determines that any arm’slength sales contract does not reflect the
total consideration actually transferred
either directly or indirectly from the
buyer to the seller, ONRR may require
that you value the oil sold under that
contract either under § 1206.103 or at
the total consideration received.
(2) You must value the oil under
§ 1206.103 if ONRR determines that the
value under paragraph (a) of this section
does not reflect the reasonable value of
the production due to either:
(i) Misconduct by or between the
parties to the arm’s-length contract; or
(ii) Breach of your duty to market the
oil for the mutual benefit of yourself and
the lessor.
(A) ONRR will not use this provision
to simply substitute its judgment of the
market value of the oil for the proceeds
received by the seller under an arm’slength sales contract.
(B) The fact that the price received by
the seller under an arm’s-length contract
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is less than other measures of market
price, such as index prices, is
insufficient to establish breach of the
duty to market unless ONRR finds
additional evidence that the seller acted
unreasonably or in bad faith in the sale
of oil from the lease.
(d)(1) If you enter into an arm’s-length
exchange agreement, or multiple
sequential arm’s-length exchange
agreements, and following the
exchange(s) you or your affiliate sell(s)
the oil received in the exchange(s)
under an arm’s-length contract, then
you may use either § 1206.102(a) or
§ 1206.103 to value your production for
royalty purposes.
(i) If you use § 1206.102(a), your gross
proceeds are the gross proceeds under
your or your affiliate’s arm’s-length
sales contract after the exchange(s)
occur(s). You must adjust your gross
proceeds for any location or quality
differential, or other adjustments, you
received or paid under the arm’s-length
exchange agreement(s). If ONRR
determines that any arm’s-length
exchange agreement does not reflect
reasonable location or quality
differentials, ONRR may require you to
value the oil under § 1206.103. You
may not otherwise use the price or
differential specified in an arm’s-length
exchange agreement to value your
production.
(ii) When you elect under
§ 1206.102(d)(1) to use § 1206.102(a) or
§ 1206.103, you must make the same
election for all of your production from
the same unit, communitization
agreement, or lease (if the lease is not
part of a unit or communitization
agreement) sold under arm’s-length
contracts following arm’s-length
exchange agreements. You may not
change your election more often than
once every 2 years.
(2)(i) If you sell or transfer your oil
production to your affiliate and that
affiliate or another affiliate then sells the
oil under an arm’s-length contract, you
may use either § 1206.102(a) or
§ 1206.103 to value your production for
royalty purposes.
(ii) When you elect under
§ 1206.102(d)(2)(i) to use § 1206.102(a)
or § 1206.103, you must make the same
election for all of your production from
the same unit, communitization
agreement, or lease (if the lease is not
part of a unit or communitization
agreement) that your affiliates resell at
arm’s length. You may not change your
election more often than once every 2
years.
(e) If you value oil under paragraph
(a) of this section:
(1) ONRR may require you to certify
that your or your affiliate’s arm’s-length
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contract provisions include all of the
consideration the buyer must pay, either
directly or indirectly, for the oil.
(2) You must base value on the
highest price the seller can receive
through legally enforceable claims
under the contract.
(i) If the seller fails to take proper or
timely action to receive prices or
benefits it is entitled to, you must pay
royalty at a value based upon that
obtainable price or benefit. But you will
owe no additional royalties unless or
until the seller receives monies or
consideration resulting from the price
increase or additional benefits, if:
(A) The seller makes timely
application for a price increase or
benefit allowed under the contract;
(B) The purchaser refuses to comply;
and
(C) The seller takes reasonable
documented measures to force
purchaser compliance.
(ii) Paragraph (e)(2)(i) of this section
will not permit you to avoid your
royalty payment obligation where a
purchaser fails to pay, pays only in part,
or pays late. Any contract revisions or
amendments that reduce prices or
benefits to which the seller is entitled
must be in writing and signed by all
parties to the arm’s-length contract.
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§ 1206.103 How do I value oil that is not
sold under an arm’s-length contract?
This section explains how to value oil
that you may not value under
§ 1206.102 or that you elect under
§ 1206.102(d) to value under this
section. First determine whether
paragraph (a), (b), or (c) of this section
applies to production from your lease,
or whether you may apply paragraph (d)
or (e) with ONRR approval.
(a) Production from leases in
California or Alaska. Value is the
average of the daily mean ANS spot
prices published in any ONRR-approved
publication during the trading month
most concurrent with the production
month. (For example, if the production
month is June, compute the average of
the daily mean prices using the daily
ANS spot prices published in the
ONRR-approved publication for all the
business days in June.)
(1) To calculate the daily mean spot
price, average the daily high and low
prices for the month in the selected
publication.
(2) Use only the days and
corresponding spot prices for which
such prices are published.
(3) You must adjust the value for
applicable location and quality
differentials, and you may adjust it for
transportation costs, under § 1206.112.
(4) After you select an ONRRapproved publication, you may not
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select a different publication more often
than once every 2 years, unless the
publication you use is no longer
published or ONRR revokes its approval
of the publication. If you are required to
change publications, you must begin a
new 2-year period.
(b) Production from leases in the
Rocky Mountain Region. This paragraph
provides methods and options for
valuing your production under different
factual situations. You must
consistently apply paragraph (b)(1), (2),
or (3) of this section to value all of your
production from the same unit,
communitization agreement, or lease (if
the lease or a portion of the lease is not
part of a unit or communitization
agreement) that you cannot value under
§ 1206.102 or that you elect under
§ 1206.102(d) to value under this
section.
(1) If you have an ONRR-approved
tendering program, you must value oil
produced from leases in the area the
tendering program covers at the highest
winning bid price for tendered volumes.
(i) The minimum requirements for
ONRR to approve your tendering
program are:
(A) You must offer and sell at least 30
percent of your or your affiliates’
production from both Federal and nonFederal leases in the area under your
tendering program; and
(B) You must receive at least three
bids for the tendered volumes from
bidders who do not have their own
tendering programs that cover some or
all of the same area.
(ii) If you do not have an ONRRapproved tendering program, you may
elect to value your oil under either
paragraph (b)(2) or (3) of this section.
After you select either paragraph (b)(2)
or (3) of this section, you may not
change to the other method more often
than once every 2 years, unless the
method you have been using is no
longer applicable and you must apply
the other paragraph. If you change
methods, you must begin a new 2-year
period.
(2) Value is the volume-weighted
average of the gross proceeds accruing
to the seller under your or your
affiliates’ 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 affiliates’
production from both Federal and nonFederal leases in the same field or area
during that month.
(ii) Before calculating the volumeweighted average, you must normalize
the quality of the oil in your or your
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affiliates’ arm’s-length purchases or
sales to the same gravity as that of the
oil produced from the lease.
(3) Value is the NYMEX price
(without the roll), adjusted for
applicable location and quality
differentials and transportation costs
under § 1206.112.
(4) If you demonstrate to ONRR’s
satisfaction that paragraphs (b)(1)
through (b)(3) of this section result in an
unreasonable value for your production
as a result of circumstances regarding
that production, the ONRR Director may
establish an alternative valuation
method.
(c) Production from leases not located
in California, Alaska, or the Rocky
Mountain Region. (1) Value is the
NYMEX price, plus the roll, adjusted for
applicable location and quality
differentials and transportation costs
under § 1206.112.
(2) If the ONRR Director determines
that use of the roll no longer reflects
prevailing industry practice in crude oil
sales contracts or that) the most
common formula used by industry to
calculate the roll changes, ONRR may
terminate or modify use of the roll
under paragraph (c)(1) of this section at
the end of each 2-year period following
July 6, 2004, through notice published
in the Federal Register not later than 60
days before the end of the 2-year period.
ONRR will explain the rationale for
terminating or modifying the use of the
roll in this notice.
(d) Unreasonable value. If ONRR
determines that the NYMEX price or
ANS spot price does not represent a
reasonable royalty value in any
particular case, ONRR may establish
reasonable royalty value based on other
relevant matters.
(e) Production delivered to your
refinery and the NYMEX price or ANS
spot price is an unreasonable value. (1)
Instead of valuing your production
under paragraph (a), (b), or (c) of this
section, you may apply to the ONRR
Director to establish a value
representing the market at the refinery
if:
(i) You transport your oil directly to
your or your affiliate’s refinery, or
exchange your oil for oil delivered to
your or your affiliate’s refinery; and
(ii) You must value your oil under
this section at the NYMEX price or ANS
spot price; and
(iii) You believe that use of the
NYMEX price or ANS spot price results
in an unreasonable royalty value.
(2) You must provide adequate
documentation and evidence
demonstrating the market value at the
refinery. That evidence may include,
but is not limited to:
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(i) Costs of acquiring other crude oil
at or for the refinery;
(ii) How adjustments for quality,
location, and transportation were
factored into the price paid for other oil;
(iii) Volumes acquired for and refined
at the refinery; and
(iv) Any other appropriate evidence or
documentation that ONRR requires.
(3) If the ONRR Director establishes a
value representing market value at the
refinery, you may not take an allowance
against that value under § 1206.112(b)
unless it is included in the Director’s
approval.
§ 1206.104 What publications are
acceptable to ONRR?
(a) ONRR periodically will publish in
the Federal Register a list of acceptable
publications for the NYMEX price and
ANS spot price based on certain criteria,
including, but not limited to:
(1) Publications buyers and sellers
frequently use;
(2) Publications frequently mentioned
in purchase or sales contracts;
(3) Publications that use adequate
survey techniques, including
development of estimates based on daily
surveys of buyers and sellers of crude
oil, and, for ANS spot prices, buyers and
sellers of ANS crude oil; and
(4) Publications independent from
ONRR, other lessors, and lessees.
(b) Any publication may petition
ONRR to be added to the list of
acceptable publications.
(c) ONRR will specify the tables you
must use in the acceptable publications.
(d) ONRR may revoke its approval of
a particular publication if it determines
that the prices or differentials published
in the publication do not accurately
represent NYMEX prices or differentials
or ANS spot market prices or
differentials.
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§ 1206.105 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 be able to show:
(1) How you calculated the value you
reported, including all adjustments for
location, quality, and transportation,
and
(2) How you complied with these
rules.
(b) Recordkeeping requirements are
found at part 1207 of this chapter.
(c) ONRR may review and audit your
data, and ONRR will direct you to use
a different value if it determines that the
reported value is inconsistent with the
requirements of this subpart.
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§ 1206.106 What are my responsibilities to
place production into marketable condition
and to market production?
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. If you use gross proceeds
under an arm’s-length contract in
determining value, you must increase
those gross proceeds to the extent that
the purchaser, or any other person,
provides certain services that the seller
normally would be responsible to
perform to place the oil in marketable
condition or to market the oil.
§ 1206.107 How do I request a value
determination?
(a) You may request a value
determination from ONRR regarding any
Federal lease oil production. Your
request must:
(1) Be in writing;
(2) Identify specifically all leases
involved, the record title or operating
rights owners of those leases, and the
designees 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) ONRR will reply to requests
expeditiously. ONRR may either:
(1) Issue a value determination signed
by the Assistant Secretary, Policy,
Management and Budget; or
(2) Issue a value determination by
ONRR; or
(3) Inform you in writing that ONRR
will not provide a value determination.
Situations in which ONRR typically will
not provide any value determination
include, but are not limited to:
(i) Requests for guidance on
hypothetical situations; and
(ii) Matters that are the subject of
pending litigation or administrative
appeals.
(c)(1) A value determination signed by
the Assistant Secretary, Policy,
Management and Budget, is binding on
both you and ONRR until the Assistant
Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues
a value determination, you must make
any adjustments in royalty payments
that follow from the determination and,
if you owe additional royalties, pay late
payment interest under § 1218.54 of this
chapter.
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(3) A value determination signed by
the Assistant Secretary is the final
action of the Department and is subject
to judicial review under 5 U.S.C. 701–
706.
(d) A value determination issued by
ONRR is binding on ONRR and
delegated States with respect to the
specific situation addressed in the
determination unless the ONRR (for
ONRR-issued value determinations) or
the Assistant Secretary modifies or
rescinds it.
(1) A value determination by ONRR is
not an appealable decision or order
under 30 CFR part 1290.
(2) If you receive an order requiring
you to pay royalty on the same basis as
the value determination, you may
appeal that order under 30 CFR part
1290.
(e) In making a value determination,
ONRR or the Assistant Secretary may
use any of the applicable valuation
criteria in this subpart.
(f) A change in an applicable statute
or regulation on which any value
determination is based takes precedence
over the value determination, regardless
of whether the ONRR or the Assistant
Secretary modifies or rescinds the value
determination.
(g) The ONRR or the Assistant
Secretary generally will not
retroactively modify or rescind a value
determination issued under paragraph
(d) of this section, unless:
(1) There was a misstatement or
omission of material facts; or
(2) The facts subsequently developed
are materially different from the facts on
which the guidance was based.
(h) ONRR may make requests and
replies under this section available to
the public, subject to the confidentiality
requirements under § 1206.108.
§ 1206.108
I provide?
Does ONRR protect information
Certain information you submit to
ONRR regarding valuation of oil,
including transportation allowances,
may be exempt from disclosure. To the
extent applicable laws and regulations
permit, ONRR will keep confidential
any data you submit that is privileged,
confidential, or otherwise exempt from
disclosure. All requests for information
must be submitted under the Freedom
of Information Act regulations of the
Department of the Interior at 43 CFR
part 2.
§ 1206.109 When may I take a
transportation allowance in determining
value?
(a) Transportation allowances
permitted when value is based on gross
proceeds. ONRR will allow a deduction
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for the reasonable, actual costs to
transport oil from the lease to the point
off the lease under § 1206.110 or
§ 1206.111, as applicable. This
paragraph applies when:
(1) You value oil under § 1206.102
based on gross proceeds from a sale at
a point off the lease, unit, or
communitized area where the oil is
produced, and
(2) The movement to the sales point
is not gathering.
(b) Transportation allowances and
other adjustments that apply when
value is based on NYMEX prices or ANS
spot prices. If you value oil using
NYMEX prices or ANS spot prices
under § 1206.103, ONRR will allow an
adjustment for certain location and
quality differentials and certain costs
associated with transporting oil as
provided under § 1206.112.
(c) Limits on transportation
allowances. (1) Except as provided in
paragraph (c)(2) of this section, your
transportation allowance may not
exceed 50 percent of the value of the oil
as determined under § 1206.102 or
§ 1206.103 of this subpart. You may not
use transportation costs incurred to
move a particular volume of production
to reduce royalties owed on production
for which those costs were not incurred.
(2) You may ask ONRR to approve a
transportation allowance in excess of
the limitation in paragraph (c)(1) of this
section. You must demonstrate that the
transportation costs incurred were
reasonable, actual, and necessary. Your
application for exception (using form
ONRR–4393, Request to Exceed
Regulatory Allowance Limitation) must
contain all relevant and supporting
documentation necessary for ONRR to
make a determination. You may never
reduce the royalty value of any
production to zero.
(d) Allocation of transportation costs.
You must allocate transportation costs
among all products produced and
transported as provided in §§ 1206.110
and 1206.111. You must express
transportation allowances for oil as
dollars per barrel.
(e) Liability for additional payments.
If ONRR determines that you took an
excessive transportation allowance, then
you must pay any additional royalties
due, plus interest under § 1218.54 of
this chapter. You also could be entitled
to a credit with interest under
applicable rules if you understated your
transportation allowance. If you take a
deduction for transportation on form
ONRR–2014 by improperly netting the
allowance against the sales value of the
oil instead of reporting the allowance as
a separate entry, ONRR may assess you
an amount under § 1206.116.
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§ 1206.110 How do I determine a
transportation allowance under an arm’slength transportation contract?
(a) If you or your affiliate incur
transportation costs under an arm’slength transportation contract, you may
claim a transportation allowance for the
reasonable, actual costs incurred as
more fully explained in paragraph (b) of
this section, except as provided in
paragraphs (a)(1) and (2) of this section
and subject to the limitation in
§ 1206.109(c). You must be able to
demonstrate that your or your affiliate’s
contract is at arm’s length. You do not
need ONRR approval before reporting a
transportation allowance for costs
incurred under an arm’s-length
transportation contract.
(1) If ONRR determines that the
contract reflects more than the
consideration actually transferred either
directly or indirectly from you or your
affiliate to the transporter for the
transportation, ONRR may require that
you calculate the transportation
allowance under § 1206.111.
(2) You must calculate the
transportation allowance under
§ 1206.111 if ONRR determines that the
consideration paid under an arm’slength transportation contract does not
reflect the reasonable value of the
transportation due to either:
(i) Misconduct by or between the
parties to the arm’s-length contract; or
(ii) Breach of your duty to market the
oil for the mutual benefit of yourself and
the lessor.
(A) ONRR will not use this provision
to simply substitute its judgment of the
reasonable oil transportation costs
incurred by you or your affiliate under
an arm’s-length transportation contract.
(B) The fact that the cost you or your
affiliate incur in an arm’s-length
transaction is higher than other
measures of transportation costs, such
as rates paid by others in the field or
area, is insufficient to establish breach
of the duty to market unless ONRR finds
additional evidence that you or your
affiliate acted unreasonably or in bad
faith in transporting oil from the lease.
(b) You may deduct any of the
following actual costs you (including
your affiliates) incur for transporting oil.
You may not use as a deduction any
cost that duplicates all or part of any
other cost that you use under this
paragraph.
(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.
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(4) The cost of carrying on your books
as inventory a volume of oil that the
pipeline operator requires you to
maintain, and that you do maintain, in
the line as line fill. You must calculate
this cost as follows:
(i) 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 § 1206.102 or
§ 1206.103, as applicable; and
(ii) Multiply the value calculated
under paragraph (b)(4)(i) of this section
by the monthly rate of return, calculated
by dividing the rate of return specified
in § 1206.111(i)(2) by 12.
(5) Fees paid to a terminal operator for
loading and unloading of crude oil into
or from a vessel, vehicle, pipeline, or
other conveyance.
(6) Fees paid for short-term storage
(30 days or less) incidental to
transportation as required by a
transporter.
(7) Fees paid to pump oil to another
carrier’s system or vehicles as required
under a tariff.
(8) 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.
(9) 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.
(10) Costs of securing a letter of credit,
or other surety, that the pipeline
requires you as a shipper to maintain.
(c) You may not deduct any costs that
are not actual costs of transporting oil,
including but not limited to the
following:
(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 your arm’s-length transportation
contract includes more than one liquid
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product, and the transportation costs
attributable to each product cannot be
determined from the contract, then you
must allocate the total transportation
costs to each of the liquid products
transported.
(1) 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
liquid products (excluding waste
products with no value).
(2) You may not claim an allowance
for the costs of transporting lease
production that is not royalty-bearing.
(3) You may propose to ONRR a cost
allocation method on the basis of the
values of the products transported.
ONRR will approve the method unless
it is not consistent with the purposes of
the regulations in this subpart.
(e) If your arm’s-length transportation
contract includes both gaseous and
liquid products, and the transportation
costs attributable to each product cannot
be determined from the contract, then
you must propose an allocation
procedure to ONRR.
(1) You may use your proposed
procedure to calculate a transportation
allowance until ONRR accepts or rejects
your cost allocation. If ONRR rejects
your cost allocation, you must amend
your form ONRR–2014 for the months
that you used the rejected method and
pay any additional royalty and interest
due.
(2) You must submit your initial
proposal, including all available data,
within 3 months after first claiming the
allocated deductions on form ONRR–
2014.
(f) If your payments for transportation
under an arm’s-length contract are not
on a dollar-per-unit basis, you must
convert whatever consideration is paid
to a dollar-value equivalent.
(g) If your arm’s-length sales contract
includes a provision reducing the
contract price by a transportation factor,
do not separately report the
transportation factor as a transportation
allowance on form ONRR–2014.
(1) You may use the transportation
factor in determining your gross
proceeds for the sale of the product.
(2) You must obtain ONRR approval
before claiming a transportation factor
in excess of 50 percent of the base price
of the product.
§ 1206.111 How do I determine a
transportation allowance if I do not have an
arm’s-length transportation contract or
arm’s-length tariff?
(a) This section applies if you or your
affiliate do not have an arm’s-length
transportation contract, including
situations where you or your affiliate
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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
include the following:
(1) Operating and maintenance
expenses under paragraphs (d) and (e) of
this section;
(2) Overhead under paragraph (f) of
this section;
(3) Depreciation under paragraphs (g)
and (h) of this section;
(4) A return on undepreciated capital
investment under paragraph (i) of this
section; and
(5) Once the transportation system has
been depreciated below ten percent of
total capital investment, a return on ten
percent of total capital investment
under paragraph (j) of this section.
(6) To the extent not included in costs
identified in paragraphs (d) through (j)
of this section, you may also deduct the
following actual costs. You may not use
any cost as a deduction that duplicates
all or part of any other cost that you use
under this section:
(i) Volumetric adjustments for actual
(not theoretical) line losses.
(ii) 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) 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 § 1206.102 or
§ 1206.103, as applicable; and
(B) Multiply the value calculated
under paragraph (b)(6)(ii)(A) of this
section by the monthly rate of return,
calculated by dividing the rate of return
specified in § 1206.111(i)(2) by 12.
(iii) 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.
(iv) 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.
(v) 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.
(vi) Fees paid to a non-affiliated
quality bank administrator for
administration of a quality bank.
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(7) You may not deduct any costs that
are not actual costs of transporting oil,
including but not limited to the
following:
(i) Fees paid for long-term storage
(more than 30 days).
(ii) Administrative, handling, and
accounting fees associated with
terminalling.
(iii) Title and terminal transfer fees.
(iv) Fees paid to track and match
receipts and deliveries at a market
center or to avoid paying title transfer
fees.
(v) Fees paid to brokers.
(vi) Fees paid to a scheduling service
provider.
(vii) 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.
(viii) Theoretical line losses.
(ix) Gauging fees.
(c) Allowable capital costs are
generally those for depreciable fixed
assets (including costs of delivery and
installation of capital equipment) which
are an integral part of the transportation
system.
(d) Allowable operating expenses
include:
(1) Operations supervision and
engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and
attributable operating expense which
you can document.
(e) Allowable maintenance expenses
include:
(1) Maintenance of the transportation
system;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and
attributable maintenance expenses
which you can document.
(f) 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.
(g) To compute depreciation, you may
elect to use either a straight-line
depreciation method based on the life of
equipment or on the life of the reserves
which the transportation system
services, or a unit-of-production
method. After you make an election,
you may not change methods without
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ONRR approval. You may not
depreciate equipment below a
reasonable salvage value.
(h) This paragraph describes the basis
for your depreciation schedule.
(1) If you or your affiliate own a
transportation system on June 1, 2000,
you must base your depreciation
schedule used in calculating actual
transportation costs for production after
June 1, 2000, on your total capital
investment in the system (including
your original purchase price or
construction cost and subsequent
reinvestment).
(2) If you or your affiliate purchased
the transportation system at arm’s
length before June 1, 2000, you must
incorporate depreciation on the
schedule based on your purchase price
(and subsequent reinvestment) into your
transportation allowance calculations
for production after June 1, 2000,
beginning at the point on the
depreciation schedule corresponding to
that date. You must prorate your
depreciation for calendar year 2000 by
claiming part-year depreciation for the
period from June 1, 2000 until
December 31, 2000. You may not adjust
your transportation costs for production
before June 1, 2000, using the
depreciation schedule based on your
purchase price.
(3) If you are the original owner of the
transportation system on June 1, 2000,
or if you purchased your transportation
system before March 1, 1988, you must
continue to use your existing
depreciation schedule in calculating
actual transportation costs for
production in periods after June 1, 2000.
(4) If you or your affiliate purchase a
transportation system at arm’s length
from the original owner after June 1,
2000, you must base your depreciation
schedule used in calculating actual
transportation costs on your total capital
investment in the system (including
your original purchase price and
subsequent reinvestment). You must
prorate your depreciation for the year in
which you or your affiliate purchased
the system to reflect the portion of that
year for which you or your affiliate own
the system.
(5) If you or your affiliate purchase a
transportation system at arm’s length
after June 1, 2000, from anyone other
than the original owner, you must
assume the depreciation schedule of the
person from whom you bought the
system. Include in the depreciation
schedule any subsequent reinvestment.
(i)(1) 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
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the transportation allowance by the rate
of return provided in paragraph (i)(2) of
this section.
(2) The rate of return is 1.3 times the
industrial bond yield index for Standard
& Poor’s BBB bond rating. Use the
monthly average rate published in
‘‘Standard & Poor’s Bond Guide’’ for the
first month of the reporting period for
which the allowance applies. Calculate
the rate at the beginning of each
subsequent transportation allowance
reporting period.
(j)(1) After a transportation system has
been depreciated at or below a value
equal to ten percent of your total capital
investment, you may continue to
include in the allowance calculation a
cost equal to ten percent of your total
capital investment in the transportation
system multiplied by a rate of return
under paragraph (i)(2) of this section.
(2) You may apply this paragraph to
a transportation system that before June
1, 2000, was depreciated at or below a
value equal to ten percent of your total
capital investment.
(k) Calculate the deduction for
transportation costs based on your or
your affiliate’s cost of transporting each
product through each individual
transportation system. Where more than
one liquid product is transported,
allocate costs consistently and equitably
to each of the liquid products
transported. Your allocation must use
the same proportion as the ratio of the
volume of each liquid product
(excluding waste products with no
value) to the volume of all liquid
products (excluding waste products
with no value).
(1) You may not take an allowance for
transporting lease production that is not
royalty-bearing.
(2) You may propose to ONRR a cost
allocation method on the basis of the
values of the products transported.
ONRR will approve the method if it is
consistent with the purposes of the
regulations in this subpart.
(l)(1) Where you transport both
gaseous and liquid products through the
same transportation system, you must
propose a cost allocation procedure to
ONRR.
(2) You may use your proposed
procedure to calculate a transportation
allowance until ONRR accepts or rejects
your cost allocation. If ONRR rejects
your cost allocation, you must amend
your form ONRR–2014 for the months
that you used the rejected method and
pay any additional royalty and interest
due.
(3) You must submit your initial
proposal, including all available data,
within 3 months after first claiming the
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36961
allocated deductions on form ONRR–
2014.
§ 1206.112 What adjustments and
transportation allowances apply when I
value oil production from my lease using
NYMEX prices or ANS spot prices?
This section applies when you use
NYMEX prices or ANS spot prices to
calculate the value of production under
§ 1206.103. As specified in this section,
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-tomarket center differential by the
applicable location and quality
differentials derived from your arm’slength exchange agreement applicable to
production during the production
month.
(ii) For oil that you exchange between
your lease and the market center (or
between any intermediate points
between those locations) under an
exchange agreement that is not at arm’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 owed
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).
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(2) For oil that you transport between
your lease and the market center (or
between any intermediate points
between those locations), you may take
an allowance for the cost of transporting
that oil between the relevant points as
determined under § 1206.110 or
§ 1206.111, 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, 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 owed 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, adjust the value
between the market center and Cushing,
Oklahoma, as follows:
(1) If you have arm’s-length exchange
agreements between the market center
and Cushing under which you exchange
to Cushing at least 20 percent of all the
oil you own at the market center during
the production month, you must use the
volume-weighted average of the location
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and quality differentials from those
agreements as the adjustment between
the market center and Cushing for all
the oil that you produce from the leases
during that production month for which
that market center is used.
(2) If paragraph (b)(1) of this section
does not apply, you must use the WTI
differential published in an ONRRapproved publication for the market
center nearest your lease, for crude oil
most similar in quality to your
production, as the adjustment between
the market center and Cushing. (For
example, for light sweet crude oil
produced offshore of Louisiana, 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 2 years, unless the
publication you use is no longer
published or ONRR revokes its approval
of the publication. If you are required to
change publications, you must begin a
new 2-year period.
(3) If neither paragraph (b)(1) nor
(b)(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 owed
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, also adjust the NYMEX
price or ANS spot price for quality
based on premiums or penalties
determined by pipeline quality bank
specifications at intermediate
commingling points or at the market
center if those points are downstream of
the royalty measurement point
approved by BSEE or BLM, as
applicable. 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
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not incorporate or provide for
adjustments for sulfur content, you may
make sulfur adjustments, based on the
quality of the representative crude oil at
the market center, of 5.0 cents per onetenth percent difference in sulfur
content, unless ONRR approves a higher
adjustment.
(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 the lessee refines the oil
received in exchange at Midland.
Assume that the NYMEX price is
$30.00/bbl, adjusted for the roll; that the
WTI differential (Cushing to Midland) is
¥$.10/bbl; that the lessee’s exchange
agreement between Roswell and
Midland results in a location and
quality differential of ¥$.08/bbl; and
that the lessee’s actual cost of
transporting the oil from Artesia to
Roswell is $.40/bbl. In this example, the
royalty value of the oil is
$30.00¥$.10¥$.08—$.40 = $29.42/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 $29.42/bbl, as explained in the
previous example. In this example, the
other 60 percent also would be valued
at $29.42/bbl.
(3) Example. Assume that a Federal
lessee produces crude oil from a lease
near Bakersfield, California. Further,
assume that the lessee transports the oil
to Hynes Station, and then exchanges
the oil to Cushing which it further
exchanges with oil it refines. Assume
that the ANS spot price is $20.00/bbl,
and that the lessee’s actual cost of
transporting the oil from Bakersfield to
Hynes Station is $.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 $.72,
including the sulfur and gravity bank
adjustments, and that ONRR approves
the lessee’s request. In this example, the
preliminary (because the location and
quality adjustment is subject to ONRR
review) royalty value of the oil is
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$20.00¥$.72¥$.28 = $19.00/bbl. The
fact that oil was exchanged to Cushing
does not change use of ANS spot prices
for royalty valuation.
§ 1206.113
centers?
How will ONRR identify market
ONRR periodically will publish in the
Federal Register a list of market centers.
ONRR will monitor market activity and,
if necessary, add to or modify the list of
market centers and will publish such
modifications in the Federal Register.
ONRR will consider the following
factors and conditions in specifying
market centers:
(a) Points where ONRR-approved
publications publish prices useful for
index purposes;
(b) Markets served;
(c) Input from industry and others
knowledgeable in crude oil marketing
and transportation;
(d) Simplification; and
(e) Other relevant matters.
§ 1206.114 What are my reporting
requirements under an arm’s-length
transportation contract?
You or your affiliate must use a
separate entry on form ONRR–2014 to
notify ONRR of an allowance based on
transportation costs you or your affiliate
incur. ONRR may require you or your
affiliate to submit arm’s-length
transportation contracts, production
agreements, operating agreements, and
related documents. Recordkeeping
requirements are found at part 1207 of
this chapter.
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§ 1206.115 What are my reporting
requirements under a non-arm’s-length
transportation arrangement?
(a) You or your affiliate must use a
separate entry on form ONRR–2014 to
notify ONRR of an allowance based on
transportation costs you or your affiliate
incur.
(b) For new transportation facilities or
arrangements, base your initial
deduction on estimates of allowable oil
transportation costs for the applicable
period. Use the most recently available
operations data for the transportation
system or, if such data are not available,
use estimates based on data for similar
transportation systems. Section
1206.117 will apply 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.
Recordkeeping requirements are found
at part 1207 of this chapter.
§ 1206.116 What interest applies if I
improperly report a transportation
allowance?
(a) If you or your affiliate deducts a
transportation allowance on form
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ONRR–2014 that exceeds 50 percent of
the value of the oil transported without
obtaining ONRR’s prior approval under
§ 1206.109, you must pay interest on
the excess allowance amount taken from
the date that amount is taken to the date
you or your affiliate files an exception
request that ONRR approves. If you do
not file an exception request, or if ONRR
does not approve your request, you
must pay interest on the excess
allowance amount taken from the date
that amount is taken until the date you
pay the additional royalties owed.
(b) If you or your affiliate takes a
deduction for transportation on form
ONRR–2014 by improperly netting an
allowance against the oil instead of
reporting the allowance as a separate
entry, ONRR may assess a civil penalty
under 30 CFR part 1241.
§ 1206.117 What reporting adjustments
must I make for transportation allowances?
(a) If your or your affiliate’s actual
transportation allowance is less than the
amount you claimed on form ONRR–
2014 for each month during the
allowance reporting period, you must
pay additional royalties plus interest
computed under § 1218.54 of this
chapter from the date you took the
deduction to the date you repay the
difference.
(b) If the actual transportation
allowance is greater than the amount
you claimed on form ONRR–2014 for
any month during the allowance form
reporting period, you are entitled to a
credit plus interest under applicable
rules.
§ 1206.119 How are royalty quantity and
quality determined?
(a) Compute royalties based on the
quantity and quality of oil as measured
at the point of settlement approved by
BLM for onshore leases or BSEE for
offshore leases.
(b) If the value of oil determined
under this subpart is based upon a
quantity or quality different from the
quantity or quality at the point of
royalty settlement approved by the BLM
for onshore leases or BSEE for offshore
leases, adjust the value for those
differences in quantity or quality.
(c) Any actual loss that you may incur
before the royalty settlement metering or
measurement point is not subject to
royalty if BLM or BSEE, as appropriate,
determines that the loss is unavoidable.
(d) Except as provided in paragraph
(b) of this section, royalties are due 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
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of royalty settlement or for theoretical
losses that are claimed to have taken
place either before or after the approved
point of royalty settlement.
§ 1206.120 How are operating allowances
determined?
BOEM may use an operating
allowance for the purpose of computing
payment obligations when specified in
the notice of sale and the lease. BOEM
will specify the allowance amount or
formula in the notice of sale and in the
lease agreement.
■ 7. Revise subpart D to read as follows:
Subpart D—Federal Gas
Sec.
1206.150 Purpose and scope.
1206.151 Definitions.
1206.152 Valuation standards—
unprocessed gas.
1206.153 Valuation standards—processed
gas.
1206.154 Determination of quantities and
qualities for computing royalties.
1206.155 Accounting for comparison.
1206.156 Transportation allowances—
general.
1206.157 Determination of transportation
allowances.
1206.158 Processing allowances—general.
1206.159 Determination of processing
allowances.
1206.160 Operating allowances.
Subpart D—Federal Gas
§ 1206.150
Purpose and scope.
(a) This subpart is applicable to all gas
production from Federal oil and gas
leases. The purpose of this subpart is to
establish the value of production for
royalty purposes consistent with the
mineral leasing laws, other applicable
laws and lease terms.
(b) If the regulations in this subpart
are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between
the United States and a lessee resulting
from administrative or judicial
litigation;
(3) A written agreement between the
lessee and the ONRR Director
establishing a method to determine the
value of production from any lease that
ONRR expects at least would
approximate the value established
under this subpart; or
(4) An express provision of an oil and
gas lease subject to this subpart; then
the statute, settlement agreement,
written agreement, or lease provision
will govern to the extent of the
inconsistency.
(c) All royalty payments made to
ONRR are subject to audit and
adjustment.
(d) The regulations in this subpart are
intended to ensure that the
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administration of oil and gas leases is
discharged in accordance with the
requirements of the governing mineral
leasing laws and lease terms.
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§ 1206.151
Definitions.
For purposes of this subpart:
Affiliate means a person who
controls, is controlled by, or is under
common control with another person.
For purposes of this subpart:
(1) Ownership or common ownership
of more than 50 percent of the voting
securities, or instruments of ownership,
or other forms of ownership, of another
person constitutes control. Ownership
of less than 10 percent constitutes a
presumption of noncontrol that ONRR
may rebut.
(2) If there is ownership or common
ownership of 10 through 50 percent of
the voting securities or instruments of
ownership, or other forms of ownership,
of another person, ONRR will consider
the following factors in determining
whether 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, whether a
person is the greatest single owner, or
whether there is an opposing voting
bloc of greater ownership;
(iii) Operation of a lease, plant,
pipeline, or other facility;
(iv) The extent of participation by
other owners in operations and day-today management of a lease, plant,
pipeline, or other facility; and
(v) Other evidence of power to
exercise control over or common control
with another person.
(3) Regardless of any percentage of
ownership or common ownership,
relatives, either by blood or marriage,
are affiliates.
Allowance means a deduction in
determining value for royalty purposes.
Processing allowance means an
allowance for the reasonable, actual
costs of processing gas determined
under this subpart. Transportation
allowance means an allowance for the
reasonable, actual costs of moving
unprocessed gas, residue gas, or gas
plant products to a point of sale or
delivery off the lease, unit area, or
communitized area, or away from a
processing plant. The transportation
allowance does not include gathering
costs.
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Area means a geographic region at
least as large as the defined limits of an
oil and/or gas field, in which oil and/
or gas lease products have similar
quality, economic, and legal
characteristics.
Arm’s-length contract means a
contract or agreement between
independent persons who are not
affiliates and who have opposing
economic interests regarding that
contract. To be considered arm’s length
for any production month, a contract
must satisfy this definition for that
month, as well as when the contract was
executed.
Audit means a review, conducted in
accordance with generally accepted
accounting and auditing standards, of
royalty payment compliance activities
of lessees or other interest holders who
pay royalties, rents, or bonuses on
Federal leases.
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.
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 resorting to processing.
Condensate is the mixture of liquid
hydrocarbons that results from
condensation of petroleum
hydrocarbons existing initially in a
gaseous phase in an underground
reservoir.
Contract means any oral or written
agreement, including amendments or
revisions thereto, between two or more
persons and enforceable by law that
with due consideration creates an
obligation.
Field means a geographic region
situated over one or more subsurface oil
and gas reservoirs encompassing at least
the outermost boundaries of all oil and
gas accumulations known to be within
those reservoirs vertically projected to
the land surface. Onshore fields are
usually given names and their official
boundaries are often designated by oil
and gas regulatory agencies in the
respective States in which the fields are
located. Outer Continental Shelf (OCS)
fields are named and their boundaries
are designated by BOEM.
Gas means any fluid, either
combustible or noncombustible,
hydrocarbon or nonhydrocarbon, which
is extracted from a reservoir and which
has neither independent shape nor
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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 and/or treatment point on
the lease, unit or communitized area, or
to a central accumulation or treatment
point off the lease, unit or
communitized area as approved by BLM
or BSEE OCS operations personnel for
onshore and OCS leases, respectively.
Gross proceeds (for royalty payment
purposes) means the total monies and
other consideration accruing to an oil
and gas lessee for the disposition of the
gas, residue gas, and gas plant products
produced. Gross proceeds includes, but
is not limited to, payments to the lessee
for certain services such as dehydration,
measurement, and/or gathering to the
extent that the lessee is obligated to
perform them at no cost to the Federal
Government. Tax reimbursements are
part of the gross proceeds accruing to a
lessee even though the Federal royalty
interest may be exempt from taxation.
Monies and other consideration,
including the forms of consideration
identified in this paragraph, to which a
lessee is contractually or legally entitled
but which it does not seek to collect
through reasonable efforts are also part
of gross proceeds.
Lease means any contract, profit-share
arrangement, joint venture, or other
agreement issued or approved by the
United States under a mineral leasing
law that authorizes exploration for,
development or extraction of, or
removal of lease products—or the land
area covered by that authorization,
whichever is required by the context.
Lease products means any leased
minerals attributable to, originating
from, or allocated to Outer Continental
Shelf or onshore Federal leases.
Lessee means any person to whom the
United States issues a lease, and any
person who has been assigned an
obligation to make royalty or other
payments required by the lease. This
includes any person who has an interest
in a lease as well as an operator or payor
who has no interest in the lease but who
has assumed the royalty payment
responsibility.
Like-quality lease products means
lease products which have similar
chemical, physical, and legal
characteristics.
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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.
Marketing affiliate means an affiliate
of the lessee whose function is to
acquire only the lessee’s production and
to market that production.
Minimum royalty means that
minimum amount of annual royalty that
the lessee must pay as specified in the
lease or in applicable leasing
regulations.
Net-back method (or work-back
method) means a method for calculating
market value of gas at the lease. Under
this method, costs of transportation,
processing, or manufacturing are
deducted from the proceeds received for
the gas, residue gas or gas plant
products, and any extracted, processed,
or manufactured products, or from the
value of the gas, residue gas or gas plant
products, and any extracted, processed,
or manufactured products, at the first
point at which reasonable values for any
such products may be determined by a
sale pursuant to an arm’s-length
contract or comparison to other sales of
such products, to ascertain value at the
lease.
Net output means the quantity of
residue gas and each gas plant product
that a processing plant produces.
Net profit share (for applicable
Federal leases) means the specified
share of the net profit from production
of oil and gas as provided in the
agreement.
Netting means the deduction of an
allowance from the sales value by
reporting a net sales value, instead of
correctly reporting the deduction as a
separate entry on form ONRR–2014.
Outer Continental Shelf (OCS) means
all submerged lands lying seaward and
outside of the area of land 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.
Person means any individual, firm,
corporation, association, partnership,
consortium, or joint venture (when
established as a separate entity).
Posted price means the price, net of
all adjustments for quality and location,
specified in publicly available price
bulletins or other price notices available
as part of normal business operations for
quantities of unprocessed gas, residue
gas, or gas plant products in marketable
condition.
Processing means any process
designed to remove elements or
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compounds (hydrocarbon and
nonhydrocarbon) from gas, including
absorption, adsorption, or refrigeration.
Field processes which normally take
place on or near the lease, such as
natural pressure reduction, mechanical
separation, heating, cooling,
dehydration, and compression, are not
considered processing. The changing of
pressures and/or temperatures in a
reservoir is not considered processing.
Residue gas means that hydrocarbon
gas consisting principally of methane
resulting from processing gas.
Sales type code means the contract
type or general disposition (e.g., arm’slength or non-arm’s-length) of
production from the lease. The sales
type code applies to the sales contract,
or other disposition, and not to the
arm’s-length or non-arm’s-length nature
of a transportation or processing
allowance.
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.
Spot sales agreement means a
contract wherein a seller agrees to sell
to a buyer a specified amount of
unprocessed gas, residue gas, or gas
plant products at a specified price over
a fixed period, usually of short duration,
which does not normally require a
cancellation notice to terminate, and
which does not contain an obligation,
nor imply an intent, to continue in
subsequent periods.
Warranty contract means a long-term
contract entered into prior to 1970,
including any amendments thereto, for
the sale of gas wherein the producer
agrees to sell a specific amount of gas
and the gas delivered in satisfaction of
this obligation may come from fields or
sources outside of the designated fields.
§ 1206.152 Valuation standards—
unprocessed gas.
(a)(1) This section applies to the
valuation of all gas that is not processed
and all gas that is processed but is sold
or otherwise disposed of by the lessee
pursuant to an arm’s-length contract
prior to processing (including all gas
where the lessee’s arm’s-length contract
for the sale of that gas prior to
processing provides for the value to be
determined on the basis of a percentage
of the purchaser’s proceeds resulting
from processing the gas). This section
also applies to processed gas that must
be valued prior to processing in
accordance with § 1206.155 of this part.
Where the lessee’s contract includes a
reservation of the right to process the
gas and the lessee exercises that right,
§ 1206.153 of this part shall apply
instead of this section.
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(2) The value of production, for
royalty purposes, of gas subject to this
subpart shall be the value of gas
determined under this section less
applicable allowances.
(b)(1)(i) The value of gas sold under
an arm’s-length contract is the gross
proceeds accruing to the lessee except
as provided in paragraphs (b)(1)(ii), (iii),
and (iv) of this section. The lessee shall
have the burden of demonstrating that
its contract is arm’s-length. The value
which the lessee reports, for royalty
purposes, is subject to monitoring,
review, and audit. For purposes of this
section, gas which is sold or otherwise
transferred to the lessee’s marketing
affiliate and then sold by the marketing
affiliate pursuant to an arm’s-length
contract shall be valued in accordance
with this paragraph based upon the sale
by the marketing affiliate. Also, where
the lessee’s arm’s-length contract for the
sale of gas prior to processing provides
for the value to be determined based
upon a percentage of the purchaser’s
proceeds resulting from processing the
gas, the value of production, for royalty
purposes, shall never be less than a
value equivalent to 100 percent of the
value of the residue gas attributable to
the processing of the lessee’s gas.
(ii) In conducting reviews and audits,
ONRR will examine whether the
contract reflects the total consideration
actually transferred either directly or
indirectly from the buyer to the seller
for the gas. If the contract does not
reflect the total consideration, then the
ONRR may require that the gas sold
pursuant to that contract be valued in
accordance with paragraph (c) of this
section. Value may not be less than the
gross proceeds accruing to the lessee,
including the additional consideration.
(iii) If the ONRR determines that the
gross proceeds accruing to the lessee
pursuant to an arm’s-length contract do
not reflect the reasonable value of the
production because of misconduct by or
between the contracting parties, or
because the lessee otherwise has
breached its duty to the lessor to market
the production for the mutual benefit of
the lessee and the lessor, then ONRR
shall require that the gas production be
valued pursuant to paragraph (c)(2) or
(c)(3) of this section, and in accordance
with the notification requirements of
paragraph (e) of this section. When
ONRR determines that the value may be
unreasonable, ONRR will notify the
lessee and give the lessee an
opportunity to provide written
information justifying the lessee’s value.
(iv) How to value over-delivered
volumes under a cash-out program: This
paragraph applies to situations where a
pipeline purchases gas from a lessee
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according to a cash-out program under
a transportation contract. For all overdelivered volumes, the royalty value is
the price the pipeline is required to pay
for volumes within the tolerances for
over-delivery specified in the
transportation contract. Use the same
value for volumes that exceed the overdelivery tolerances even if those
volumes are subject to a lower price
under the transportation contract.
However, if ONRR determines that the
price specified in the transportation
contract for over-delivered volumes is
unreasonably low, the lessee must value
all over-delivered volumes under
paragraph (c)(2) or (3) of this section.
(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, the
value of gas sold pursuant to a warranty
contract shall be determined by ONRR,
and due consideration will be given to
all valuation criteria specified in this
section. The lessee must request a value
determination in accordance with
paragraph (g) of this section for gas sold
pursuant to a warranty contract;
provided, however, that any value
determination for a warranty contract in
effect on the effective date of these
regulations shall remain in effect until
modified by ONRR.
(3) ONRR may require a lessee to
certify that its arm’s-length contract
provisions include all of the
consideration to be paid by the buyer,
either directly or indirectly, for the gas.
(c) The value of gas subject to this
section which is not sold pursuant to an
arm’s-length contract shall be the
reasonable value determined in
accordance with the first applicable of
the following methods:
(1) The gross proceeds accruing to the
lessee pursuant to a sale under its nonarm’s-length contract (or other
disposition other than by an arm’slength contract), provided that those
gross proceeds are equivalent to the
gross proceeds derived from, or paid
under, comparable arm’s-length
contracts for purchases, sales, or other
dispositions of like-quality gas in the
same field (or, if necessary to obtain a
reasonable sample, from the same area).
In evaluating the comparability of arm’slength contracts for the purposes of
these regulations, the following factors
shall be considered: Price, time of
execution, duration, market or markets
served, terms, quality of gas, volume,
and such other factors as may be
appropriate to reflect the value of the
gas;
(2) A value determined by
consideration of other information
relevant in valuing like-quality gas,
including gross proceeds under arm’slength contracts for like-quality gas in
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the same field or nearby fields or areas,
posted prices for gas, prices received in
arm’s-length spot sales of gas, other
reliable public sources of price or
market information, and other
information as to the particular lease
operation or the saleability of the gas; or
(3) A net-back method or any other
reasonable method to determine value.
(d)(1) Notwithstanding any other
provisions of this section, except
paragraph (h) of this section, if the
maximum price permitted by Federal
law at which gas may be sold is less
than the value determined pursuant to
this section, then ONRR shall accept
such maximum price as the value. For
purposes of this section, price
limitations set by any State or local
government shall not be considered as
a maximum price permitted by Federal
law.
(2) The limitation prescribed in
paragraph (d)(1) of this section shall not
apply to gas sold pursuant to a warranty
contract and valued pursuant to
paragraph (b)(2) of this section.
(e)(1) Where the value is determined
pursuant to paragraph (c) of this section,
the lessee shall retain all data relevant
to the determination of royalty value.
Such data shall be subject to review and
audit, and ONRR will direct a lessee to
use a different value if it determines that
the reported value is inconsistent with
the requirements of these regulations.
(2) Any Federal lessee will make
available upon request to the authorized
ONRR or State representatives, to the
Office of the Inspector General of the
Department of the Interior, or other
person authorized to receive such
information, arm’s-length sales and
volume data for like-quality production
sold, purchased or otherwise obtained
by the lessee from the field or area or
from nearby fields or areas.
(3) A lessee shall notify ONRR if it has
determined value pursuant to paragraph
(c)(2) or (3) of this section. The
notification shall be by letter to the
ONRR Director for Office of Natural
Resources Revenue or his/her designee.
The letter shall identify the valuation
method to be used and contain a brief
description of the procedure to be
followed. The notification required by
this paragraph is a one-time notification
due no later than the end of the month
following the month the lessee first
reports royalties on a form ONRR–2014
using a valuation method authorized by
paragraph (c)(2) or (3) of this section,
and each time there is a change in a
method under paragraph (c)(2) or (3) of
this section.
(f) If ONRR determines that a lessee
has not properly determined value, the
lessee shall pay the difference, if any,
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between royalty payments made based
upon the value it has used and the
royalty payments that are due based
upon the value established by ONRR.
The lessee shall also pay interest on that
difference computed pursuant to
§ 1218.54 of this chapter. If the lessee is
entitled to a credit, ONRR will provide
instructions for the taking of that credit.
(g) The lessee may request a value
determination from ONRR. In that
event, the lessee shall propose to ONRR
a value determination method, and may
use that method in determining value
for royalty purposes until ONRR issues
its decision. The lessee shall submit all
available data relevant to its proposal.
The ONRR shall expeditiously
determine the value based upon the
lessee’s proposal and any additional
information ONRR deems necessary. In
making a value determination ONRR
may use any of the valuation criteria
authorized by this subpart. That
determination shall remain effective for
the period stated therein. After ONRR
issues its determination, the lessee shall
make the adjustments in accordance
with paragraph (f) of this section.
(h) Notwithstanding any other
provision of this section, under no
circumstances shall the value of
production for royalty purposes be less
than the gross proceeds accruing to the
lessee for lease production, less
applicable allowances.
(i) The lessee must place gas in
marketable condition and market the gas
for the mutual benefit of the lessee and
the lessor at no cost to the Federal
Government. Where the value
established under this section is
determined by a lessee’s gross proceeds,
that value will be increased to the extent
that the gross proceeds have been
reduced because the purchaser, or any
other person, is providing certain
services the cost of which ordinarily is
the responsibility of the lessee to place
the gas in marketable condition or to
market the gas.
(j) Value shall be based on the highest
price a prudent lessee can receive
through legally enforceable claims
under its contract. If there is no contract
revision or amendment, and the lessee
fails to take proper or timely action to
receive prices or benefits to which it is
entitled, it must pay royalty at a value
based upon that obtainable price or
benefit. Contract revisions or
amendments shall be in writing and
signed by all parties to an arm’s-length
contract. If the lessee makes timely
application for a price increase or
benefit allowed under its contract but
the purchaser refuses, and the lessee
takes reasonable measures, which are
documented, to force purchaser
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compliance, the lessee will owe no
additional royalties unless or until
monies or consideration resulting from
the price increase or additional benefits
are received. This paragraph shall not be
construed to permit a lessee to avoid its
royalty payment obligation in situations
where a purchaser fails to pay, in whole
or in part or timely, for a quantity of gas.
(k) Notwithstanding any provision in
these regulations to the contrary, no
review, reconciliation, monitoring, or
other like process that results in a
redetermination by ONRR of value
under this section shall be considered
final or binding as against the Federal
Government or its beneficiaries until the
audit period is formally closed.
(l) Certain information submitted to
ONRR to support valuation proposals,
including transportation or
extraordinary cost allowances, is
exempted from disclosure by the
Freedom of Information Act, 5 U.S.C.
552, or other Federal law. Any data
specified by law to be privileged,
confidential, or otherwise exempt will
be maintained in a confidential manner
in accordance with applicable law and
regulations. All requests for information
about determinations made under this
subpart are to be submitted in
accordance with the Freedom of
Information Act regulation of the
Department of the Interior, 43 CFR part
2.
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§ 1206.153 Valuation standards—
processed gas.
(a)(1) This section applies to the
valuation of all gas that is processed by
the lessee and any other gas production
to which this subpart applies and that
is not subject to the valuation provisions
of § 1206.152 of this part. This section
applies where the lessee’s contract
includes a reservation of the right to
process the gas and the lessee exercises
that right.
(2) The value of production, for
royalty purposes, of gas subject to this
section shall be the combined value of
the residue gas and all gas plant
products determined pursuant to this
section, plus the value of any
condensate recovered downstream of
the point of royalty settlement without
resorting to processing determined
pursuant to § 1206.102 of this part, less
applicable transportation allowances
and processing allowances determined
pursuant to this subpart.
(b)(1)(i) The value of residue gas or
any gas plant product sold under an
arm’s-length contract is the gross
proceeds accruing to the lessee, except
as provided in paragraphs (b)(1)(ii), (iii),
and (iv) of this section. The lessee shall
have the burden of demonstrating that
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its contract is arm’s-length. The value
that the lessee reports for royalty
purposes is subject to monitoring,
review, and audit. For purposes of this
section, residue gas or any gas plant
product which is sold or otherwise
transferred to the lessee’s marketing
affiliate and then sold by the marketing
affiliate pursuant to an arm’s-length
contract shall be valued in accordance
with this paragraph based upon the sale
by the marketing affiliate.
(ii) In conducting these reviews and
audits, ONRR will examine whether or
not the contract reflects the total
consideration actually transferred either
directly or indirectly from the buyer to
the seller for the residue gas or gas plant
product. If the contract does not reflect
the total consideration, then the ONRR
may require that the residue gas or gas
plant product sold pursuant to that
contract be valued in accordance with
paragraph (c) of this section. Value may
not be less than the gross proceeds
accruing to the lessee, including the
additional consideration.
(iii) If the ONRR determines that the
gross proceeds accruing to the lessee
pursuant to an arm’s-length contract do
not reflect the reasonable value of the
residue gas or gas plant product because
of misconduct by or between the
contracting parties, or because the lessee
otherwise has breached its duty to the
lessor to market the production for the
mutual benefit of the lessee and the
lessor, then ONRR shall require that the
residue gas or gas plant product be
valued pursuant to paragraph (c)(2) or
(3) of this section, and in accordance
with the notification requirements of
paragraph (e) of this section. When
ONRR determines that the value may be
unreasonable, ONRR will notify the
lessee and give the lessee an
opportunity to provide written
information justifying the lessee’s value.
(iv) How to value over-delivered
volumes under a cash-out program: This
paragraph applies to situations where a
pipeline purchases gas from a lessee
according to a cash-out program under
a transportation contract. For all overdelivered volumes, the royalty value is
the price the pipeline is required to pay
for volumes within the tolerances for
over-delivery specified in the
transportation contract. Use the same
value for volumes that exceed the overdelivery tolerances even if those
volumes are subject to a lower price
under the transportation contract.
However, if ONRR determines that the
price specified in the transportation
contract for over-delivered volumes is
unreasonably low, the lessee must value
all over-delivered volumes under
paragraph (c)(2) or (3) of this section.
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(2) Notwithstanding the provisions of
paragraph (b)(1) of this section, the
value of residue gas sold pursuant to a
warranty contract shall be determined
by ONRR, and due consideration will be
given to all valuation criteria specified
in this section. The lessee must request
a value determination in accordance
with paragraph (g) of this section for gas
sold pursuant to a warranty contract;
provided, however, that any value
determination for a warranty contract in
effect on the effective date of these
regulations shall remain in effect until
modified by ONRR.
(3) ONRR may require a lessee to
certify that its arm’s-length contract
provisions include all of the
consideration to be paid by the buyer,
either directly or indirectly, for the
residue gas or gas plant product.
(c) The value of residue gas or any gas
plant product which is not sold
pursuant to an arm’s-length contract
shall be the reasonable value
determined in accordance with the first
applicable of the following methods:
(1) The gross proceeds accruing to the
lessee pursuant to a sale under its nonarm’s-length contract (or other
disposition other than by an arm’slength contract), provided that those
gross proceeds are equivalent to the
gross proceeds derived from, or paid
under, comparable arm’s-length
contracts for purchases, sales, or other
dispositions of like quality residue gas
or gas plant products from the same
processing plant (or, if necessary to
obtain a reasonable sample, from nearby
plants). In evaluating the comparability
of arm’s-length contracts for the
purposes of these regulations, the
following factors shall be considered:
Price, time of execution, duration,
market or markets served, terms, quality
of residue gas or gas plant products,
volume, and such other factors as may
be appropriate to reflect the value of the
residue gas or gas plant products;
(2) A value determined by
consideration of other information
relevant in valuing like-quality residue
gas or gas plant products, including
gross proceeds under arm’s-length
contracts for like-quality residue gas or
gas plant products from the same gas
plant or other nearby processing plants,
posted prices for residue gas or gas plant
products, prices received in spot sales of
residue gas or gas plant products, other
reliable public sources of price or
market information, and other
information as to the particular lease
operation or the saleability of such
residue gas or gas plant products; or
(3) A net-back method or any other
reasonable method to determine value.
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(d)(1) Notwithstanding any other
provisions of this section, except
paragraph (h) of this section, if the
maximum price permitted by Federal
law at which any residue gas or gas
plant products may be sold is less than
the value determined pursuant to this
section, then ONRR shall accept such
maximum price as the value. For the
purposes of this section, price
limitations set by any State or local
government shall not be considered as
a maximum price permitted by Federal
law.
(2) The limitation prescribed by
paragraph (d)(1) of this section shall not
apply to residue gas sold pursuant to a
warranty contract and valued pursuant
to paragraph (b)(2) of this section.
(e)(1) Where the value is determined
pursuant to paragraph (c) of this section,
the lessee shall retain all data relevant
to the determination of royalty value.
Such data shall be subject to review and
audit, and ONRR will direct a lessee to
use a different value if it determines
upon review or audit that the reported
value is inconsistent with the
requirements of these regulations.
(2) Any Federal lessee will make
available upon request to the authorized
ONRR or State representatives, to the
Office of the Inspector General of the
Department of the Interior, or other
persons authorized to receive such
information, arm’s-length sales and
volume data for like-quality residue gas
and gas plant products sold, purchased
or otherwise obtained by the lessee from
the same processing plant or from
nearby processing plants.
(3) A lessee shall notify ONRR if it has
determined any value pursuant to
paragraph (c)(2) or (3) of this section.
The notification shall be by letter to the
ONRR Director for Office of Natural
Resources or his/her designee. The letter
shall identify the valuation method to
be used and contain a brief description
of the procedure to be followed. The
notification required by this paragraph
is a one-time notification due no later
than the end of the month following the
month the lessee first reports royalties
on a form ONRR–2014 using a valuation
method authorized by paragraph (c)(2)
or (3) of this section, and each time
there is a change in a method under
paragraph (c)(2) or (3) of this section.
(f) If ONRR determines that a lessee
has not properly determined value, the
lessee shall pay the difference, if any,
between royalty payments made based
upon the value it has used and the
royalty payments that are due based
upon the value established by ONRR.
The lessee shall also pay interest
computed on that difference pursuant to
§ 1218.54 of this chapter. If the lessee is
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entitled to a credit, ONRR will provide
instructions for the taking of that credit.
(g) The lessee may request a value
determination from ONRR. In that
event, the lessee shall propose to ONRR
a value determination method, and may
use that method in determining value
for royalty purposes until ONRR issues
its decision. The lessee shall submit all
available data relevant to its proposal.
The ONRR shall expeditiously
determine the value based upon the
lessee’s proposal and any additional
information ONRR deems necessary. In
making a value determination, ONRR
may use any of the valuation criteria
authorized by this subpart. That
determination shall remain effective for
the period stated therein. After ONRR
issues its determination, the lessee shall
make the adjustments in accordance
with paragraph (f) of this section.
(h) Notwithstanding any other
provision of this section, under no
circumstances shall the value of
production for royalty purposes be less
than the gross proceeds accruing to the
lessee for residue gas and/or any gas
plant products, less applicable
transportation allowances and
processing allowances determined
pursuant to this subpart.
(i) The lessee must place residue gas
and gas plant products in marketable
condition and market the residue gas
and gas plant products for the mutual
benefit of the lessee and the lessor at no
cost to the Federal Government. Where
the value established under this section
is determined by a lessee’s gross
proceeds, that value will be increased to
the extent that the gross proceeds have
been reduced because the purchaser, or
any other person, is providing certain
services the cost of which ordinarily is
the responsibility of the lessee to place
the residue gas or gas plant products in
marketable condition or to market the
residue gas and gas plant products.
(j) Value shall be based on the highest
price a prudent lessee can receive
through legally enforceable claims
under its contract. Absent contract
revision or amendment, if the lessee
fails to take proper or timely action to
receive prices or benefits to which it is
entitled it must pay royalty at a value
based upon that obtainable price or
benefit. Contract revisions or
amendments shall be in writing and
signed by all parties to an arm’s-length
contract. If the lessee makes timely
application for a price increase or
benefit allowed under its contract but
the purchaser refuses, and the lessee
takes reasonable measures, which are
documented, to force purchaser
compliance, the lessee will owe no
additional royalties unless or until
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monies or consideration resulting from
the price increase or additional benefits
are received. This paragraph shall not be
construed to permit a lessee to avoid its
royalty payment obligation in situations
where a purchaser fails to pay, in whole
or in part, or timely, for a quantity of
residue gas or gas plant product.
(k) Notwithstanding any provision in
these regulations to the contrary, no
review, reconciliation, monitoring, or
other like process that results in a
redetermination by ONRR of value
under this section shall be considered
final or binding against the Federal
Government or its beneficiaries until the
audit period is formally closed.
(l) Certain information submitted to
ONRR to support valuation proposals,
including transportation allowances,
processing allowances or extraordinary
cost allowances, is exempted from
disclosure by the Freedom of
Information Act, 5 U.S.C. 552, or other
Federal law. Any data specified by law
to be privileged, confidential, or
otherwise exempt, will be maintained in
a confidential manner in accordance
with applicable law and regulations. All
requests for information about
determinations made under this part are
to be submitted in accordance with the
Freedom of Information Act regulation
of the Department of the Interior, 43
CFR part 2.
§ 1206.154 Determination of quantities
and qualities for computing royalties.
(a)(1) Royalties shall be computed on
the basis of the quantity and quality of
unprocessed gas at the point of royalty
settlement approved by BLM or BSEE
for onshore and OCS leases,
respectively.
(2) If the value of gas determined
pursuant to § 1206.152 of this subpart is
based upon a quantity and/or quality
that is different from the quantity and/
or quality at the point of royalty
settlement, as approved by BLM or
BSEE, that value shall be adjusted 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 the value of residue gas and/or
gas plant products determined pursuant
to § 1206.153 of this subpart is based
upon 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 in
accordance with paragraph (c) of this
section, that value shall be adjusted for
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the differences in quantity and/or
quality.
(c) The quantity of the residue gas and
gas plant products attributable to a lease
shall be determined according to the
following procedure:
(1) When the net output of the
processing plant is derived from gas
obtained from only one lease, the
quantity of the residue gas and gas plant
products on which computations of
royalty are based is the net output of the
plant.
(2) When the net output of a
processing plant is derived from gas
obtained from more than one lease
producing gas of uniform content, the
quantity of the residue gas and gas plant
products allocable to each lease shall be
in 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 nonuniform content,
the quantity of the residue gas allocable
to each lease will be determined by
multiplying the amount of gas delivered
to the plant from the lease by the
residue gas content of the gas, and
dividing the arithmetical product thus
obtained 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. The net output of gas plant
products allocable to each lease will be
determined by multiplying the amount
of gas delivered to the plant from the
lease by the gas plant product content
of the gas, and dividing the arithmetical
product thus obtained 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) A lessee may request ONRR
approval of other methods for
determining the quantity of residue gas
and gas plant products allocable to each
lease. If approved, such method will be
applicable to all gas production from
Federal leases that is processed in the
same plant.
(d)(1) No deductions may be made
from the royalty volume or royalty value
for actual or theoretical losses. Any
actual loss of unprocessed gas that may
be sustained prior to the royalty
settlement metering or measurement
point will not be subject to royalty
provided that such loss is determined to
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have been unavoidable by BLM or
BSEE, as appropriate.
(2) Except as provided in paragraph
(d)(1) of this section and § 1202.151(c),
royalties are due on 100 percent of the
volume determined in accordance with
paragraphs (a) through (c) of this
section. There can be no reduction in
that determined volume for actual losses
after the quantity basis has been
determined or for theoretical losses that
are claimed 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. There can be no deduction
from the value of the unprocessed gas,
residue gas, and/or gas plant products to
compensate for actual losses after the
quantity basis has been determined, or
for theoretical losses that are claimed to
have taken place.
§ 1206.155
Accounting for comparison.
(a) Except as provided in paragraph
(b) of this section, where the lessee (or
a person to whom the lessee has
transferred gas pursuant to a non-arm’slength contract or without a contract)
processes the lessee’s gas and after
processing the gas the residue gas is not
sold pursuant to an arm’s-length
contract, the value, for royalty purposes,
shall be the greater of:
(1) The combined value, for royalty
purposes, of the residue gas and gas
plant products resulting from processing
the gas determined pursuant to
§ 1206.153 of this subpart, plus the
value, for royalty purposes, of any
condensate recovered downstream of
the point of royalty settlement without
resorting to processing determined
pursuant to § 1206.102 of this subpart;
or
(2) The value, for royalty purposes, of
the gas prior to processing determined
in accordance with § 1206.152 of this
subpart.
(b) The requirement for accounting for
comparison contained in the terms of
leases will govern as provided in
§ 1206.150(b) of this subpart. When
accounting for comparison is required
by the lease terms, such accounting for
comparison shall be determined in
accordance with paragraph (a) of this
section.
§ 1206.156
general.
Transportation allowances—
(a) Where the value of gas has been
determined pursuant to § 1206.152 or
§ 1206.153 of this subpart at a point
(e.g., sales point or point of value
determination) off the lease, ONRR shall
allow a deduction for the reasonable
actual costs incurred by the lessee to
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36969
transport unprocessed gas, residue gas,
and gas plant products from a lease to
a point off the lease including, if
appropriate, transportation from the
lease to a gas processing plant off the
lease and from the plant to a point away
from the plant.
(b) Transportation costs must be
allocated among all products produced
and transported as provided in
§ 1206.157.
(c)(1) Except as provided in paragraph
(c)(3) of this section, for unprocessed
gas valued in accordance with
§ 1206.152 of this subpart, the
transportation allowance deduction on
the basis of a sales type code may not
exceed 50 percent of the value of the
unprocessed gas determined under
§ 1206.152 of this subpart.
(2) Except as provided in paragraph
(c)(3) of this section, for gas production
valued in accordance with § 1206.153 of
this subpart, the transportation
allowance deduction on the basis of a
sales type code may not exceed 50
percent of the value of the residue gas
or gas plant product determined under
§ 1206.153 of this subpart. For purposes
of this section, natural gas liquids will
be considered one product.
(3) Upon request of a lessee, ONRR
may approve a transportation allowance
deduction in excess of the limitations
prescribed by paragraphs (c)(1) and (2)
of this section. The lessee must
demonstrate that the transportation
costs incurred in excess of the
limitations prescribed in paragraphs
(c)(1) and (2) of this section were
reasonable, actual, and necessary. An
application for exception (using form
ONRR–4393, Request to Exceed
Regulatory Allowance Limitation) must
contain all relevant and supporting
documentation necessary for ONRR to
make a determination. Under no
circumstances may the value for royalty
purposes under any sales type code be
reduced to zero.
(d) If, after a review or audit, ONRR
determines that a lessee has improperly
determined a transportation allowance
authorized by this subpart, then the
lessee must pay any additional royalties,
plus interest, determined in accordance
with § 1218.54 of this chapter, or will
be entitled to a credit, with interest. If
the lessee takes a deduction for
transportation on form ONRR–2014 by
improperly netting the allowance
against the sales value of the
unprocessed gas, residue gas, and gas
plant products instead of reporting the
allowance as a separate entry, ONRR
may assess a civil penalty under 30 CFR
part 1241.
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§ 1206.157 Determination of
transportation allowances.
(a) Arm’s-length transportation
contracts. (1)(i) For transportation costs
incurred by a lessee under an arm’slength contract, the transportation
allowance shall be the reasonable,
actual costs incurred by the lessee for
transporting the unprocessed gas,
residue gas and/or gas plant products
under that contract, except as provided
in paragraphs (a)(1)(ii) and (iii) of this
section, subject to monitoring, review,
audit, and adjustment. The lessee shall
have the burden of demonstrating that
its contract is arm’s-length. ONRR’s
prior approval is not required before a
lessee may deduct costs incurred under
an arm’s-length contract. Such
allowances shall be subject to the
provisions of paragraph (f) of this
section. The lessee must claim a
transportation allowance by reporting it
as a separate entry on the form ONRR–
2014.
(ii) In conducting reviews and audits,
ONRR will examine whether or not the
contract reflects more than the
consideration actually transferred either
directly or indirectly from the lessee to
the transporter for the transportation. If
the contract reflects more than the total
consideration, then the ONRR may
require that the transportation
allowance be determined in accordance
with paragraph (b) of this section.
(iii) If the ONRR determines that the
consideration paid pursuant to an arm’slength transportation contract does not
reflect the reasonable value of the
transportation because of misconduct by
or between the contracting parties, or
because the lessee otherwise has
breached its duty to the lessor to market
the production for the mutual benefit of
the lessee and the lessor, then ONRR
shall require that the transportation
allowance be determined in accordance
with paragraph (b) of this section. When
ONRR determines that the value of the
transportation may be unreasonable,
ONRR will notify the lessee and give the
lessee an opportunity to provide written
information justifying the lessee’s
transportation costs.
(2)(i) If an arm’s-length transportation
contract includes more than one
product in a gaseous phase and the
transportation costs attributable to each
product cannot be determined from the
contract, the total transportation costs
shall be allocated in a consistent and
equitable manner to each of the
products transported in the same
proportion as the ratio of the volume of
each product (excluding waste products
which have no value) to the volume of
all products in the gaseous phase
(excluding waste products which have
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no value). Except as provided in this
paragraph, no allowance may be taken
for the costs of transporting lease
production which is not royalty bearing
without ONRR approval.
(ii) Notwithstanding the requirements
of paragraph (a)(2)(i) of this section, the
lessee may propose to ONRR a cost
allocation method on the basis of the
values of the products transported.
ONRR shall approve the method unless
it determines that it is not consistent
with the purposes of the regulations in
this part.
(3) If an arm’s-length transportation
contract includes both gaseous and
liquid products and the transportation
costs attributable to each cannot be
determined from the contract, the lessee
shall propose an allocation procedure to
ONRR. The lessee may use the
transportation allowance determined in
accordance with its proposed allocation
procedure until ONRR issues its
determination on the acceptability of
the cost allocation. The lessee shall
submit all relevant data to support its
proposal. ONRR shall then determine
the gas transportation allowance based
upon the lessee’s proposal and any
additional information ONRR deems
necessary. The lessee must submit the
allocation proposal within 3 months of
claiming the allocated deduction on the
form ONRR–2014.
(4) Where the lessee’s payments for
transportation under an arm’s-length
contract are not based on a dollar per
unit, the lessee shall convert whatever
consideration is paid to a dollar value
equivalent for the purposes of this
section.
(5) Where an arm’s-length sales
contract price or a posted price includes
a provision whereby the listed price is
reduced by a transportation factor,
ONRR will not consider the
transportation factor to be a
transportation allowance. The
transportation factor may be used in
determining the lessee’s gross proceeds
for the sale of the product. The
transportation factor may not exceed 50
percent of the base price of the product
without ONRR approval.
(b) Non-arm’s-length or no contract.
(1) If a lessee has a non-arm’s-length
transportation contract or has no
contract, including those situations
where the lessee performs
transportation services for itself, the
transportation allowance will be based
upon the lessee’s reasonable actual costs
as provided in this paragraph. All
transportation allowances deducted
under a non-arm’s-length or no contract
situation are subject to monitoring,
review, audit, and adjustment. The
lessee must claim a transportation
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allowance by reporting it as a separate
entry on the form ONRR–2014. When
necessary or appropriate, ONRR may
direct a lessee to modify its estimated or
actual transportation allowance
deduction.
(2) The transportation allowance for
non-arm’s-length or no-contract
situations shall be based upon the
lessee’s actual costs for transportation
during the reporting period, including
operating and maintenance expenses,
overhead, and either depreciation and a
return on undepreciated capital
investment in accordance with
paragraph (b)(2)(iv)(A) of this section, or
a cost equal to the initial depreciable
investment in the transportation system
multiplied by a rate of return in
accordance with paragraph (b)(2)(iv)(B)
of this section. Allowable capital costs
are generally those costs for depreciable
fixed assets (including costs of delivery
and installation of capital equipment)
which are an integral part of the
transportation system.
(i) Allowable operating expenses
include: Operations supervision and
engineering; operations labor; fuel;
utilities; materials; ad valorem property
taxes; rent; supplies; and any other
directly allocable and attributable
operating expense which the lessee can
document.
(ii) Allowable maintenance expenses
include: Maintenance of the
transportation system; maintenance of
equipment; maintenance labor; and
other directly allocable and attributable
maintenance expenses which the lessee
can document.
(iii) Overhead directly attributable
and allocable to the operation and
maintenance of the transportation
system is an allowable expense. State
and Federal income taxes and severance
taxes and other fees, including royalties,
are not allowable expenses.
(iv) A lessee may use either
depreciation or a return on depreciable
capital investment. After a lessee has
elected to use either method for a
transportation system, the lessee may
not later elect to change to the other
alternative without approval of the
ONRR.
(A) To compute depreciation, the
lessee may elect to use either a straightline depreciation method based on the
life of equipment or on the life of the
reserves which the transportation
system services, or a unit of production
method. After an election is made, the
lessee may not change methods without
ONRR approval. A change in ownership
of a transportation system shall not alter
the depreciation schedule established
by the original transporter/lessee for
purposes of the allowance calculation.
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With or without a change in ownership,
a transportation system shall be
depreciated only once. Equipment shall
not be depreciated below a reasonable
salvage value.
(B) The ONRR shall allow as a cost an
amount equal to the allowable initial
capital investment in the transportation
system multiplied by the rate of return
determined pursuant to paragraph
(b)(2)(v) of this section. No allowance
shall be provided for depreciation. This
alternative shall apply only to
transportation facilities first placed in
service after March 1, 1988.
(v) The rate of return must be 1.3
times the industrial rate associated with
Standard & Poor’s BBB rating. The BBB
rate must be the monthly average rate as
published in Standard & Poor’s Bond
Guide for the first month for which the
allowance is applicable. The rate must
be redetermined at the beginning of
each subsequent calendar year.
(3)(i) The deduction for transportation
costs shall be determined on the basis
of the lessee’s cost of transporting each
product through each individual
transportation system. Where more than
one product in a gaseous phase is
transported, the allocation of costs to
each of the products transported shall
be made in a consistent and equitable
manner in the same proportion as the
ratio of the volume of each product
(excluding waste products which have
no value) to the volume of all products
in the gaseous phase (excluding waste
products which have no value). Except
as provided in this paragraph, the lessee
may not take an allowance for
transporting a product which is not
royalty bearing without ONRR approval.
(ii) Notwithstanding the requirements
of paragraph (b)(3)(i) of this section, the
lessee may propose to the ONRR a cost
allocation method on the basis of the
values of the products transported.
ONRR shall approve the method unless
it determines that it is not consistent
with the purposes of the regulations in
this part.
(4) Where both gaseous and liquid
products are transported through the
same transportation system, the lessee
shall propose a cost allocation
procedure to ONRR. The lessee may use
the transportation allowance
determined in accordance with its
proposed allocation procedure until
ONRR issues its determination on the
acceptability of the cost allocation. The
lessee shall submit all relevant data to
support its proposal. ONRR shall then
determine the transportation allowance
based upon the lessee’s proposal and
any additional information ONRR
deems necessary. The lessee must
submit the allocation proposal within 3
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months of claiming the allocated
deduction on the form ONRR–2014.
(5) You may apply for an exception
from the requirement to compute actual
costs under paragraphs (b)(1) through
(4) of this section.
(i) ONRR will grant the exception if:
(A) The transportation system has a
tariff filed with the Federal Energy
Regulatory Commission (FERC) or a
State regulatory agency, that FERC or
the State regulatory agency has
permitted to become effective, and
(B) Third parties are paying prices,
including discounted prices, under the
tariff to transport gas on the system
under arm’s-length transportation
contracts.
(ii) If ONRR approves the exception,
you must calculate your transportation
allowance for each production month
based on the lesser of the volumeweighted average of the rates paid by
the third parties under arm’s-length
transportation contracts during that
production month or the non-arm’slength payment by the lessee to the
pipeline.
(iii) If during any production month
there are no prices paid under the tariff
by third parties to transport gas on the
system under arm’s-length
transportation contracts, you may use
the volume-weighted average of the
rates paid by third parties under arm’slength transportation contracts in the
most recent preceding production
month in which the tariff remains in
effect and third parties paid such rates,
for up to five successive production
months. You must use the non-arm’slength payment by the lessee to the
pipeline if it is less than the volumeweighted average of the rates paid by
third parties under arm’s-length
contracts.
(c) Reporting requirements—(1)
Arm’s-length contracts. (i) You must use
a separate entry on form ONRR–2014 to
notify ONRR of a transportation
allowance.
(ii) ONRR may require you to submit
arm’s-length transportation contracts,
production agreements, operating
agreements, and related documents.
Recordkeeping requirements are found
at part 1207 of this chapter.
(iii) You may not use a transportation
allowance that was in effect before
March 1, 1988. You must use the
provisions of this subpart to determine
your transportation allowance.
(2) Non-arm’s-length or no contract.
(i) You must use a separate entry on
form ONRR–2014 to notify ONRR of a
transportation allowance.
(ii) For new transportation facilities or
arrangements, base your initial
deduction on estimates of allowable gas
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36971
transportation costs for the applicable
period. Use the most recently available
operations data for the transportation
system or, if such data are not available,
use estimates based on data for similar
transportation systems. Paragraph (e) of
this section will apply when you amend
your report based on your actual costs.
(iii) ONRR may require you to submit
all data used to calculate the allowance
deduction. Recordkeeping requirements
are found at part 1207 of this chapter.
(iv) If you are authorized under
paragraph (b)(5) of this section to use an
exception to the requirement to
calculate your actual transportation
costs, you must follow the reporting
requirements of paragraph (c)(1) of this
section.
(v) You may not use a transportation
allowance that was in effect before
March 1, 1988. You must use the
provisions of this subpart to determine
your transportation allowance.
(d) Interest and assessments. (1) If a
lessee deducts a transportation
allowance on its form ONRR–2014 that
exceeds 50 percent of the value of the
gas transported without obtaining prior
approval of ONRR under § 1206.156, the
lessee shall pay interest on the excess
allowance amount taken from the date
such amount is taken to the date the
lessee files an exception request with
ONRR.
(2) If a lessee erroneously reports a
transportation allowance which results
in an underpayment of royalties,
interest shall be paid on the amount of
that underpayment.
(3) Interest required to be paid by this
section shall be determined in
accordance with § 1218.54 of this
chapter.
(e) Adjustments. (1) If the actual
transportation allowance is less than the
amount the lessee has taken on form
ONRR–2014 for each month during the
allowance reporting period, the lessee
shall be required to pay additional
royalties due plus interest computed
under § 1218.54 of this chapter from the
allowance reporting period when the
lessee took the deduction to the date the
lessee repays the difference to ONRR. If
the actual transportation allowance is
greater than the amount the lessee has
taken on form ONRR–2014 for each
month during the allowance reporting
period, the lessee shall be entitled to a
credit without interest.
(2) For lessees transporting
production from onshore Federal leases,
the lessee must submit a corrected form
ONRR–2014 to reflect actual costs,
together with any payment, in
accordance with instructions provided
by ONRR.
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(3) For lessees transporting gas
production from leases on the OCS, if
the lessee’s estimated transportation
allowance exceeds the allowance based
on actual costs, the lessee must submit
a corrected form ONRR–2014 to reflect
actual costs, together with its payment,
in accordance with instructions
provided by ONRR. If the lessee’s
estimated transportation allowance is
less than the allowance based on actual
costs, the refund procedure will be
specified by ONRR.
(f) Allowable costs in determining
transportation allowances. You may
include, but are not limited to (subject
to the requirements of paragraph (g) of
this section), the following costs in
determining the arm’s-length
transportation allowance under
paragraph (a) of this section or the nonarm’s-length transportation allowance
under paragraph (b) 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 paragraph.
(1) Firm demand charges paid to
pipelines. You may deduct firm demand
charges or capacity reservation fees paid
to a pipeline, including charges or fees
for unused firm capacity that you have
not sold before you report your
allowance. If you receive 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 receive
a payment or credit from the pipeline
for penalty refunds, rate case refunds, or
other reasons, you must reduce the firm
demand charge claimed on the form
ONRR–2014 by the amount of that
payment. You must modify the form
ONRR–2014 by the amount received or
credited for the affected reporting
period, and pay any resulting royalty
and late payment interest due;
(2) Gas supply realignment (GSR)
costs. The GSR costs result from a
pipeline reforming or terminating
supply contracts with producers to
implement the restructuring
requirements of FERC Orders in 18 CFR
part 284;
(3) Commodity charges. The
commodity charge allows the pipeline
to recover the costs of providing service;
(4) Wheeling costs. Hub operators
charge a wheeling cost for transporting
gas from one pipeline to either the same
or another pipeline through a market
center or hub. A hub is a connected
manifold of pipelines through which a
series of incoming pipelines are
interconnected to a series of outgoing
pipelines;
(5) Gas Research Institute (GRI) fees.
The GRI conducts research,
development, and commercialization
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programs on natural gas related topics
for the benefit of the U.S. gas industry
and gas customers. GRI fees are
allowable provided such fees are
mandatory in FERC-approved tariffs;
(6) Annual Charge Adjustment (ACA)
fees. FERC charges these fees to
pipelines to pay for its operating
expenses;
(7) Payments (either volumetric or in
value) for actual or theoretical losses.
However, theoretical losses are not
deductible in non-arm’s-length
transportation arrangements unless the
transportation allowance is based on
arm’s-length transportation rates
charged under a FERC- or State
regulatory-approved tariff under
paragraph (b)(5) of this section. If you
receive volumes or credit for line gain,
you must reduce your transportation
allowance accordingly and pay any
resulting royalties and late payment
interest due;
(8) Temporary storage services. This
includes short duration storage services
offered by market centers or hubs
(commonly referred to as ‘‘parking’’ or
‘‘banking’’), or other temporary storage
services provided by pipeline
transporters, whether actual or provided
as a matter of accounting. Temporary
storage is limited to 30 days or less; and
(9) Supplemental costs for
compression, dehydration, and
treatment of gas. ONRR allows these
costs only if such services are required
for transportation and exceed the
services necessary to place production
into marketable condition required
under §§ 1206.152(i) and 1206.153(i) of
this part.
(10) Costs of surety. You may deduct
the costs of securing a letter of credit, or
other surety, that the pipeline requires
you as a shipper to maintain under an
arm’s-length transportation contract.
(g) Nonallowable costs in determining
transportation allowances. Lessees may
not include the following costs in
determining the arm’s-length
transportation allowance under
paragraph (a) of this section or the nonarm’s-length transportation allowance
under paragraph (b) of this section:
(1) Fees or costs incurred for storage.
This includes storing production in a
storage facility, whether on or off the
lease, for more than 30 days;
(2) Aggregator/marketer fees. This
includes fees you pay to another person
(including your affiliates) to market
your gas, including purchasing and
reselling the gas, or finding or
maintaining a market for the gas
production;
(3) Penalties you incur as shipper.
These penalties include, but are not
limited to:
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(i) Over-delivery cash-out penalties.
This includes the difference between
the price the pipeline pays you for overdelivered volumes outside the
tolerances and the price you receive for
over-delivered volumes within the
tolerances;
(ii) Scheduling penalties. This
includes penalties you incur for
differences between daily volumes
delivered into the pipeline and volumes
scheduled or nominated at a receipt or
delivery point;
(iii) Imbalance penalties. This
includes penalties you incur (generally
on a monthly basis) for differences
between volumes delivered into the
pipeline and volumes scheduled or
nominated at a receipt or delivery point;
and
(iv) Operational penalties. This
includes fees you incur for violation of
the pipeline’s curtailment or operational
orders issued to protect the operational
integrity of the pipeline;
(4) Intra-hub transfer fees. These are
fees you pay to hub operators for
administrative services (e.g., title
transfer tracking) necessary to account
for the sale of gas within a hub;
(5) Fees paid to brokers. This includes
fees paid 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 paid to
parties who provide scheduling
services, if such fees are separately
identified from aggregator/marketer fees;
(7) Internal costs. This includes
salaries and related costs, rent/space
costs, office equipment costs, legal fees,
and other costs to schedule, nominate,
and account for sale or movement of
production; and
(8) Other nonallowable costs. Any
cost you incur for services you are
required to provide at no cost to the
lessor.
(h) Other transportation cost
determinations. Use this section when
calculating transportation costs to
establish value using a netback
procedure or any other procedure that
requires deduction of transportation
costs.
§ 1206.158
general.
Processing allowances—
(a) Where the value of gas is
determined pursuant to § 1206.153 of
this subpart, a deduction shall be
allowed for the reasonable actual costs
of processing.
(b) Processing costs must be allocated
among the gas plant products. A
separate processing allowance must be
determined for each gas plant product
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and processing plant relationship.
Natural gas liquids (NGL’s) shall be
considered as one product.
(c)(1) Except as provided in paragraph
(d)(2) of this section, the processing
allowance shall not be applied against
the value of the residue gas. Where there
is no residue gas ONRR may designate
an appropriate gas plant product against
which no allowance may be applied.
(2) Except as provided in paragraph
(c)(3) of this section, the processing
allowance deduction on the basis of an
individual product shall not exceed
66 2⁄3 percent of the value of each gas
plant product determined in accordance
with § 1206.153 of this subpart (such
value to be reduced first for any
transportation allowances related to
postprocessing transportation
authorized by § 1206.156 of this
subpart).
(3) Upon request of a lessee, ONRR
may approve a processing allowance in
excess of the limitation prescribed by
paragraph (c)(2) of this section. The
lessee must demonstrate that the
processing costs incurred in excess of
the limitation prescribed in paragraph
(c)(2) of this section were reasonable,
actual, and necessary. An application
for exception (using form ONRR–4393,
Request to Exceed Regulatory
Allowance Limitation) shall contain all
relevant and supporting documentation
for ONRR to make a determination.
Under no circumstances shall the value
for royalty purposes of any gas plant
product be reduced to zero.
(d)(1) Except as provided in paragraph
(d)(2) of this section, no processing cost
deduction shall be allowed 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. Where
gas is processed for the removal of acid
gases, commonly referred to as
‘‘sweetening,’’ no processing cost
deduction shall be allowed for such
costs unless the acid gases removed are
further processed into a gas plant
product. In such event, the lessee shall
be eligible for a processing allowance as
determined in accordance with this
subpart. However, ONRR will not grant
any processing allowance for processing
lease production which is not royalty
bearing.
(2)(i) If the lessee incurs extraordinary
costs for processing gas production from
a gas production operation, it may apply
to ONRR for an allowance for those
costs which shall be in addition to any
other processing allowance to which the
lessee is entitled pursuant to this
section. Such an allowance may be
granted only if the lessee can
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demonstrate that the costs are, by
reference to standard industry
conditions and practice, extraordinary,
unusual, or unconventional.
(ii) Prior ONRR approval to continue
an extraordinary processing cost
allowance is not required. However, to
retain the authority to deduct the
allowance the lessee must report the
deduction to ONRR in a form and
manner prescribed by ONRR.
(e) If ONRR determines that a lessee
has improperly determined a processing
allowance authorized by this subpart,
then the lessee must pay any additional
royalties, plus interest determined
under § 1218.54 of this chapter, or will
be entitled to a credit with interest. If
the lessee takes a deduction for
processing on form ONRR–2014 by
improperly netting the allowance
against the sales value of the gas plant
products instead of reporting the
allowance as a separate entry, ONRR
may assess a civil penalty under 30 CFR
part 1241.
§ 1206.159 Determination of processing
allowances.
(a) Arm’s-length processing contracts.
(1)(i) For processing costs incurred by a
lessee under an arm’s-length contract,
the processing allowance shall be the
reasonable actual costs incurred by the
lessee for processing the gas under that
contract, except as provided in
paragraphs (a)(1)(ii) and (iii) of this
section, subject to monitoring, review,
audit, and adjustment. The lessee shall
have the burden of demonstrating that
its contract is arm’s-length. ONRR’s
prior approval is not required before a
lessee may deduct costs incurred under
an arm’s-length contract. The lessee
must claim a processing allowance by
reporting it as a separate entry on the
form ONRR–2014.
(ii) In conducting reviews and audits,
ONRR will examine whether the
contract reflects more than the
consideration actually transferred either
directly or indirectly from the lessee to
the processor for the processing. If the
contract reflects more than the total
consideration, then the ONRR may
require that the processing allowance be
determined in accordance with
paragraph (b) of this section.
(iii) If ONRR determines that the
consideration paid pursuant to an arm’slength processing contract does not
reflect the reasonable value of the
processing because of misconduct by or
between the contracting parties, or
because the lessee otherwise has
breached its duty to the lessor to market
the production for the mutual benefit of
the lessee and lessor, then ONRR shall
require that the processing allowance be
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36973
determined in accordance with
paragraph (b) of this section. When
ONRR determines that the value of the
processing may be unreasonable, ONRR
will notify the lessee and give the lessee
an opportunity to provide written
information justifying the lessee’s
processing costs.
(2) If an arm’s-length processing
contract includes more than one gas
plant product and the processing costs
attributable to each product can be
determined from the contract, then the
processing costs for each gas plant
product shall be determined in
accordance with the contract. No
allowance may be taken for the costs of
processing lease production which is
not royalty-bearing.
(3) If an arm’s-length processing
contract includes more than one gas
plant product and the processing costs
attributable to each product cannot be
determined from the contract, the lessee
shall propose an allocation procedure to
ONRR. The lessee may use its proposed
allocation procedure until ONRR issues
its determination. The lessee shall
submit all relevant data to support its
proposal. ONRR shall then determine
the processing allowance based upon
the lessee’s proposal and any additional
information ONRR deems necessary. No
processing allowance will be granted for
the costs of processing lease production
which is not royalty bearing. The lessee
must submit the allocation proposal
within 3 months of claiming the
allocated deduction on form ONRR–
2014.
(4) Where the lessee’s payments for
processing under an arm’s-length
contract are not based on a dollar per
unit basis, the lessee shall convert
whatever consideration is paid to a
dollar value equivalent for the purposes
of this section.
(b) Non-arm’s-length or no contract.
(1) If a lessee has a non-arm’s-length
processing contract or has no contract,
including those situations where the
lessee performs processing for itself, the
processing allowance will be based
upon the lessee’s reasonable actual costs
as provided in this paragraph. All
processing allowances deducted under a
non-arm’s-length or no-contract
situation are subject to monitoring,
review, audit, and adjustment. The
lessee must claim a processing
allowance by reflecting it as a separate
entry on the form ONRR–2014. When
necessary or appropriate, ONRR may
direct a lessee to modify its estimated or
actual processing allowance.
(2) The processing allowance for nonarm’s-length or no-contract situations
shall be based upon the lessee’s actual
costs for processing during the reporting
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period, including operating and
maintenance expenses, overhead, and
either depreciation and a return on
undepreciated capital investment in
accordance with paragraph (b)(2)(iv)(A)
of this section, or a cost equal to the
initial depreciable investment in the
processing plant multiplied by a rate of
return in accordance with paragraph
(b)(2)(iv)(B) of this section. Allowable
capital costs are generally those costs for
depreciable fixed assets (including costs
of delivery and installation of capital
equipment) which are an integral part of
the processing plant.
(i) Allowable operating expenses
include: Operations supervision and
engineering; operations labor; fuel;
utilities; materials; ad valorem property
taxes; rent; supplies; and any other
directly allocable and attributable
operating expense which the lessee can
document.
(ii) Allowable maintenance expenses
include: Maintenance of the processing
plant; maintenance of equipment;
maintenance labor; and other directly
allocable and attributable maintenance
expenses which the lessee can
document.
(iii) Overhead directly attributable
and allocable to the operation and
maintenance of the processing plant is
an allowable expense. State and Federal
income taxes and severance taxes,
including royalties, are not allowable
expenses.
(iv) A lessee may use either
depreciation or a return on depreciable
capital investment. When a lessee has
elected to use either method for a
processing plant, the lessee may not
later elect to change to the other
alternative without approval of the
ONRR.
(A) To compute depreciation, the
lessee may elect to use either a straightline depreciation method based on the
life of equipment or on the life of the
reserves which the processing plant
services, or a unit-of-production
method. After an election is made, the
lessee may not change methods without
ONRR approval. A change in ownership
of a processing plant shall not alter the
depreciation schedule established by
the original processor/lessee for
purposes of the allowance calculation.
With or without a change in ownership,
a processing plant shall be depreciated
only once. Equipment shall not be
depreciated below a reasonable salvage
value.
(B) The ONRR shall allow as a cost an
amount equal to the allowable initial
capital investment in the processing
plant multiplied by the rate of return
determined pursuant to paragraph
(b)(2)(v) of this section. No allowance
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shall be provided for depreciation. This
alternative shall apply only to plants
first placed in service after March 1,
1988.
(v) The rate of return must be the
industrial rate associated with Standard
and Poor’s BBB rating. The rate of return
must be the monthly average rate as
published in Standard and Poor’s Bond
Guide for the first month for which the
allowance is applicable. The rate must
be redetermined at the beginning of
each subsequent calendar year.
(3) The processing allowance for each
gas plant product shall be determined
based on the lessee’s reasonable and
actual cost of processing the gas.
Allocation of costs to each gas plant
product shall be based upon generally
accepted accounting principles. The
lessee may not take an allowance for the
costs of processing lease production
which is not royalty bearing.
(4) A lessee may apply to ONRR for
an exception from the requirement that
it compute actual costs in accordance
with paragraphs (b)(1) through (b)(3) of
this section. The ONRR may grant the
exception only if: (i) The lessee 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 pursuant to arm’slength processing contracts; if the ONRR
grants the exception, the lessee shall use
as its processing allowance the volume
weighted average prices charged other
persons pursuant to arm’s-length
contracts for processing at the same
plant.
(c) Reporting requirements—(1)
Arm’s-length contracts. (i) The lessee
must notify ONRR of an allowance
based on incurred costs by using a
separate entry on the form ONRR–2014.
(ii) ONRR may require that a lessee
submit arm’s-length processing
contracts and related documents.
Documents shall be submitted within a
reasonable time, as determined by
ONRR.
(2) Non-arm’s-length or no contract.
(i) The lessee must notify ONRR of an
allowance based on the incurred costs
by using a separate entry on the form
ONRR–2014.
(ii) For new processing plants, the
lessee’s initial deduction shall include
estimates of the allowable gas
processing costs for the applicable
period. Cost estimates shall be based
upon the most recently available
operations data for the plant or, if such
data are not available, the lessee shall
use estimates based upon industry data
for similar gas processing plants.
(iii) Upon request by ONRR, the lessee
shall submit all data used to prepare the
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allowance deduction. The data shall be
provided within a reasonable period of
time, as determined by ONRR.
(iv) If the lessee is authorized to use
the volume weighted average prices
charged other persons as its processing
allowance in accordance with paragraph
(b)(4) of this section, it shall follow the
reporting requirements of paragraph
(c)(1) of this section.
(d) Interest. (1) If a lessee deducts a
processing allowance on its form
ONRR–2014 that exceeds 66 2⁄3 percent
of the value of the gas processed
without obtaining prior approval of
ONRR under § 1206.158, the lessee shall
pay interest on the excess allowance
amount taken from the date such
amount is taken to the date the lessee
files an exception request with ONRR.
(2) If a lessee erroneously reports a
processing allowance which results in
an underpayment of royalties, interest
shall be paid on the amount of that
underpayment.
(3) Interest required to be paid by this
section shall be determined in
accordance with § 1218.54 of this
chapter.
(e) Adjustments. (1) If the actual
processing allowance is less than the
amount the lessee has taken on form
ONRR–2014 for each month during the
allowance reporting period, the lessee
shall pay additional royalties due plus
interest computed under § 1218.54 of
this chapter from the allowance
reporting period when the lessee took
the deduction to the date the lessee
repays the difference to ONRR. If the
actual processing allowance is greater
than the amount the lessee has taken on
form ONRR–2014 for each month during
the allowance reporting period, the
lessee shall be entitled to a credit with
interest.
(2) For lessees processing production
from onshore Federal leases, the lessee
must submit a corrected form ONRR–
2014 to reflect actual costs, together
with any payment, in accordance with
instructions provided by ONRR.
(3) For lessees processing gas
production from leases on the OCS, if
the lessee’s estimated processing
allowance exceeds the allowance based
on actual costs, the lessee must submit
a corrected form ONRR–2014 to reflect
actual costs, together with its payment,
in accordance with instructions
provided by ONRR. If the lessee’s
estimated costs were less than the actual
costs, the refund procedure will be
specified by ONRR.
(f) Other processing cost
determinations. The provisions of this
section shall apply to determine
processing costs when establishing
value using a net back valuation
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procedure or any other procedure that
requires deduction of processing costs.
§ 1206.160
Operating allowances.
Notwithstanding any other provisions
in these regulations, an operating
allowance may be used for the purpose
of computing payment obligations when
specified in the notice of sale and the
lease. The allowance amount or formula
shall be specified in the notice of sale
and in the lease agreement.
■ 8. Revise subpart F to read as follows:
Subpart F—Federal Coal
Sec.
1206.250 Purpose and scope.
1206.251 Definitions.
1206.252 Information collection.
1206.253 Coal subject to royalties—general
provisions.
1206.254 Quality and quantity
measurement standards for reporting and
paying royalties.
1206.255 Point of royalty determination.
1206.256 Valuation standards for cents-perton leases.
1206.257 Valuation standards for ad
valorem leases.
1206.258 Washing allowances—general.
1206.259 Determination of washing
allowances.
1206.260 Allocation of washed coal.
1206.261 Transportation allowances—
general.
1206.262 Determination of transportation
allowances.
1206.263 [Reserved]
1206.264 In-situ and surface gasification
and liquefaction operations.
1206.265 Value enhancement of marketable
coal.
Subpart F—Federal Coal
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§ 1206.250
Purpose and scope.
(a) This subpart is applicable to all
coal produced from Federal coal leases.
The purpose of this subpart is to
establish the value of coal produced for
royalty purposes, of all coal from
Federal leases consistent with the
mineral leasing laws, other applicable
laws and lease terms.
(b) If the specific provisions of any
statute or settlement agreement between
the United States and a lessee resulting
from administrative or judicial
litigation, or any coal lease subject to
the requirements of this subpart, are
inconsistent with any regulation in this
subpart then the statute, lease provision,
or settlement shall govern to the extent
of that inconsistency.
(c) All royalty payments made to the
Office of Natural Resources Revenue
(ONRR) are subject to later audit and
adjustment.
§ 1206.251
Definitions.
Ad valorem lease means a lease where
the royalty due to the lessor is based
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upon a percentage of the amount or
value of the coal.
Allowance means a deduction used in
determining value for royalty purposes.
Coal washing allowance means an
allowance for the reasonable, actual
costs incurred by the lessee for coal
washing. Transportation allowance
means an allowance for the reasonable,
actual costs incurred by the lessee for
moving coal to a point of sale or point
of delivery remote from both the lease
and mine or wash plant.
Area means a geographic region in
which coal has 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 that has been
arrived at in the marketplace between
independent, nonaffiliated persons with
opposing economic interests regarding
that contract. For purposes of this
subpart, two persons are affiliated if one
person controls, is controlled by, or is
under common control with another
person. For purposes of this subpart,
based on the instruments of ownership
of the voting securities of an entity, or
based on other forms of ownership:
(a) Ownership in excess of 50 percent
constitutes control;
(b) Ownership of 10 through 50
percent creates a presumption of
control; and
(c) Ownership of less than 10 percent
creates a presumption of noncontrol
which ONRR may rebut if it
demonstrates actual or legal control,
including the existence of interlocking
directorates.
Notwithstanding any other provisions
of this subpart, contracts between
relatives, either by blood or by marriage,
are not arm’s-length contracts. The
ONRR may require the lessee to certify
ownership control. To be considered
arm’s-length for any production month,
a contract must meet the requirements
of this definition for that production
month as well as when the contract was
executed.
Audit means a review, conducted in
accordance with generally accepted
accounting and auditing standards, of
royalty payment compliance activities
of lessees or other interest holders who
pay royalties, rents, or bonuses on
Federal leases.
BLM means the Bureau of Land
Management of the Department of the
Interior.
Coal means coal of all ranks from
lignite through anthracite.
Coal washing means any treatment to
remove impurities from coal. Coal
washing may include, but is not limited
to, operations such as flotation, air,
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water, or heavy media separation;
drying; and related handling (or
combination thereof).
Contract means any oral or written
agreement, including amendments or
revisions thereto, between two or more
persons and enforceable by law that
with due consideration creates an
obligation.
Gross proceeds (for royalty payment
purposes) means the total monies and
other consideration accruing to a coal
lessee for the production and
disposition of the coal produced. Gross
proceeds includes, but is not limited to,
payments to the lessee for certain
services such as crushing, sizing,
screening, storing, mixing, loading,
treatment with substances including
chemicals or oils, and other preparation
of the coal to the extent that the lessee
is obligated to perform them at no cost
to the Federal Government. Gross
proceeds, as applied to coal, also
includes but is not limited to
reimbursements for royalties, taxes or
fees, and other reimbursements. Tax
reimbursements are part of the gross
proceeds accruing to a lessee even
though the Federal royalty interest may
be exempt from taxation. Monies and
other consideration, including the forms
of consideration identified in this
paragraph, to which a lessee is
contractually or legally entitled but
which it does not seek to collect through
reasonable efforts are also part of gross
proceeds.
Lease means any contract, profit-share
arrangement, joint venture, or other
agreement issued or approved by the
United States for a Federal coal resource
under a mineral leasing law that
authorizes exploration for, development
or extraction of, or removal of coal—or
the land covered by that authorization,
whichever is required by the context.
Lessee means any person to whom the
United States issues a lease, and any
person who has been assigned an
obligation to make royalty or other
payments required by the lease. This
includes any person who has an interest
in a lease as well as an operator or payor
who has no interest in the lease but who
has assumed the royalty payment
responsibility.
Like-quality coal means coal that has
similar chemical and physical
characteristics.
Marketable condition means coal that
is sufficiently free from impurities and
otherwise in a condition that it will be
accepted by a purchaser under a sales
contract typical for that area.
Mine means an underground or
surface excavation or series of
excavations and the surface or
underground support facilities that
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contribute directly or indirectly to
mining, production, preparation, and
handling of lease products.
Net-back method means a method for
calculating market value of coal at the
lease or mine. Under this method, costs
of transportation, washing, handling,
etc., are deducted from the ultimate
proceeds received for the coal at the first
point at which reasonable values for the
coal may be determined by a sale
pursuant to an arm’s-length contract or
by comparison to other sales of coal, to
ascertain value at the mine.
Net output means the quantity of
washed coal that a washing plant
produces.
Netting is the deduction of an
allowance from the sales value by
reporting a one line net sales value,
instead of correctly reporting the
deduction as a separate line item on the
form ONRR–4430.
Person means by individual, firm,
corporation, association, partnership,
consortium, or joint venture.
Sales type code means the contract
type or general disposition (e.g., arm’slength or non-arm’s-length) of
production from the lease. The sales
type code applies to the sales contract,
or other disposition, and not to the
arm’s-length or non-arm’s-length nature
of a transportation or washing
allowance.
Spot market price means the price
received under any sales transaction
when planned or actual deliveries span
a short period of time, usually not
exceeding one year.
§ 1206.252
Information collection.
The information collection
requirements contained in this subpart
have been approved by the Office of
Management and Budget (OMB) under
44 U.S.C. 3501 et seq. The forms, filing
date, and approved OMB control
numbers are identified in part 1210—
Forms and Reports.
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§ 1206.253 Coal subject to royalties—
general provisions.
(a) All coal (except coal unavoidably
lost as determined by BLM under 43
CFR part 3400) from a Federal lease
subject to this part is subject to royalty.
This includes coal used, sold, or
otherwise disposed of by the lessee on
or off the lease.
(b) If a lessee receives compensation
for unavoidably lost coal through
insurance coverage or other
arrangements, royalties at the rate
specified in the lease are to be paid on
the amount of compensation received
for the coal. No royalty is due on
insurance compensation received by the
lessee for other losses.
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(c) If waste piles or slurry ponds are
reworked to recover coal, the lessee
shall pay royalty at the rate specified in
the lease at the time the recovered coal
is used, sold, or otherwise finally
disposed of. The royalty rate shall be
that rate applicable to the production
method used to initially mine coal in
the waste pile or slurry pond; i.e.,
underground mining method or surface
mining method. Coal in waste pits or
slurry ponds initially mined from
Federal leases shall be allocated to such
leases regardless of whether it is stored
on Federal lands. The lessee shall
maintain accurate records to determine
to which individual Federal lease coal
in the waste pit or slurry pond should
be allocated. However, nothing in this
section requires payment of a royalty on
coal for which a royalty has already
been paid.
§ 1206.254 Quality and quantity
measurement standards for reporting and
paying royalties.
For all leases subject to this subpart,
the quantity of coal on which royalty is
due shall be measured in short tons (of
2,000 pounds each) by methods
prescribed by the BLM. Coal quantity
information will be reported on
appropriate forms required under 30
CFR part 1210—Forms and Reports.
§ 1206.255
Point of royalty determination.
(a) For all leases subject to this
subpart, royalty shall be computed on
the basis of the quantity and quality of
Federal coal in marketable condition
measured at the point of royalty
measurement as determined jointly by
BLM and ONRR.
(b) Coal produced and added to
stockpiles or inventory does not require
payment of royalty until such coal is
later used, sold, or otherwise finally
disposed of. ONRR may ask BLM to
increase the lease bond to protect the
lessor’s interest when BLM determines
that stockpiles or inventory become
excessive so as to increase the risk of
degradation of the resource.
(c) The lessee shall pay royalty at a
rate specified in the lease at the time the
coal is used, sold, or otherwise finally
disposed of, unless otherwise provided
for at § 1206.256(d) of this subpart.
§ 1206.256 Valuation standards for centsper-ton leases.
(a) This section is applicable to coal
leases on Federal lands which provide
for the determination of royalty on a
cents-per-ton (or other quantity) basis.
(b) The royalty for coal from leases
subject to this section shall be based on
the dollar rate per ton prescribed in the
lease. That dollar rate shall be
applicable to the actual quantity of coal
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used, sold, or otherwise finally disposed
of, including coal which is avoidably
lost as determine by BLM pursuant to 43
CFR part 3400.
(c) For leases subject to this section,
there shall be no allowances for
transportation, removal of impurities,
coal washing, or any other processing or
preparation of the coal.
(d) When a coal lease is readjusted
pursuant to 43 CFR part 3400 and the
royalty valuation method changes from
a cents-per-ton basis to an ad valorem
basis, coal which is produced prior to
the effective date of readjustment and
sold or used within 30 days of the
effective date of readjustment shall be
valued pursuant to this section. All coal
that is not used, sold, or otherwise
finally disposed of within 30 days after
the effective date of readjustment shall
be valued pursuant to the provisions of
§ 1206.257 of this subpart, and royalties
shall be paid at the royalty rate specified
in the readjusted lease.
§ 1206.257 Valuation standards for ad
valorem leases.
(a) This section is applicable to coal
leases on Federal lands which provide
for the determination of royalty as a
percentage of the amount of value of
coal (ad valorem). The value for royalty
purposes of coal from such leases shall
be the value of coal determined under
this section, less applicable coal
washing allowances and transportation
allowances determined under
§§ 1206.258 through 1206.262 of this
subpart, or any allowance authorized by
§ 1206.265 of this subpart. The royalty
due shall be equal to the value for
royalty purposes multiplied by the
royalty rate in the lease.
(b)(1) The value of coal that is sold
pursuant to an arm’s-length contract
shall be the gross proceeds accruing to
the lessee, except as provided in
paragraphs (b)(2), (3), and (5) of this
section. The lessee shall have the
burden of demonstrating that its
contract is arm’s-length. The value
which the lessee reports, for royalty
purposes, is subject to monitoring,
review, and audit.
(2) In conducting reviews and audits,
ONRR will examine whether the
contract reflects the total consideration
actually transferred either directly or
indirectly from the buyer to the seller
for the coal produced. If the contract
does not reflect the total consideration,
then the ONRR may require that the coal
sold pursuant to that contract be valued
in accordance with paragraph (c) of this
section. Value may not be based on less
than the gross proceeds accruing to the
lessee for the coal production, including
the additional consideration.
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(3) If ONRR determines that the gross
proceeds accruing to the lessee pursuant
to an arm’s-length contract do not reflect
the reasonable value of the production
because of misconduct by or between
the contracting parties, or because the
lessee otherwise has breached its duty
to the lessor to market the production
for the mutual benefit of the lessee and
the lessor, then ONRR shall require that
the coal production be valued pursuant
to paragraph (c)(2)(ii), (iii), (iv), or (v) of
this section, and in accordance with the
notification requirements of paragraph
(d)(3) of this section. When ONRR
determines that the value may be
unreasonable, ONRR will notify the
lessee and give the lessee an
opportunity to provide written
information justifying the lessee’s
reported coal value.
(4) ONRR may require a lessee to
certify that its arm’s-length contract
provisions include all of the
consideration to be paid by the buyer,
either directly or indirectly, for the coal
production.
(5) The value of production for royalty
purposes shall not include payments
received by the lessee pursuant to a
contract which the lessee demonstrates,
to ONRR’s satisfaction, were not part of
the total consideration paid for the
purchase of coal production.
(c)(1) The value of coal from leases
subject to this section and which is not
sold pursuant to an arm’s-length
contract shall be determined in
accordance with this section.
(2) If the value of the coal cannot be
determined pursuant to paragraph (b) of
this section, then the value shall be
determined through application of other
valuation criteria. The criteria shall be
considered in the following order, and
the value shall be based upon the first
applicable criterion:
(i) The gross proceeds accruing to the
lessee pursuant to a sale under its nonarm’s-length contract (or other
disposition of produced coal by other
than an arm’s-length contract), provided
that those gross proceeds are within the
range of the gross proceeds derived
from, or paid under, comparable arm’slength contracts between buyers and
sellers neither of whom is affiliated with
the lessee for sales, purchases, or other
dispositions of like-quality coal
produced in the area. In evaluating the
comparability of arm’s-length contracts
for the purposes of these regulations, the
following factors shall be considered:
Price, time of execution, duration,
market or markets served, terms, quality
of coal, quantity, and such other factors
as may be appropriate to reflect the
value of the coal;
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(ii) Prices reported for that coal to a
public utility commission;
(iii) Prices reported for that coal to the
Energy Information Administration of
the Department of Energy;
(iv) Other relevant matters including,
but not limited to, published or publicly
available spot market prices, or
information submitted by the lessee
concerning circumstances unique to a
particular lease operation or the
saleability of certain types of coal;
(v) If a reasonable value cannot be
determined using paragraphs (c)(2) (i),
(ii), (iii), or (iv) of this section, then a
net-back method or any other reasonable
method shall be used to determine
value.
(3) When the value of coal is
determined pursuant to paragraph (c)(2)
of this section, that value determination
shall be consistent with the provisions
contained in paragraph (b)(5) of this
section.
(d)(1) Where the value is determined
pursuant to paragraph (c) of this section,
that value does not require ONRR’s
prior approval. However, the lessee
shall retain all data relevant to the
determination of royalty value. Such
data shall be subject to review and
audit, and ONRR will direct a lessee to
use a different value if it determines that
the reported value is inconsistent with
the requirements of these regulations.
(2) Any Federal lessee will make
available upon request to the authorized
ONRR or State representatives, to the
Inspector General of the Department of
the Interior or other persons authorized
to receive such information, arm’slength sales value and sales quantity
data for like-quality coal sold,
purchased, or otherwise obtained by the
lessee from the area.
(3) A lessee shall notify ONRR if it has
determined value pursuant to
paragraphs (c)(2)(ii), (iii), (iv), or (v) of
this section. The notification shall be by
letter to the Director for Office of
Natural Resources Revenue of his/her
designee. The letter shall identify the
valuation method to be used and
contain a brief description of the
procedure to be followed. The
notification required by this section is a
one-time notification due no later than
the month the lessee first reports
royalties on the form ONRR–4430 using
a valuation method authorized by
paragraphs (c)(2)(ii), (iii), (iv), or (v) of
this section, and each time there is a
change in a method under paragraphs
(c)(2)(iv) or (v) of this section.
(e) If ONRR determines that a lessee
has not properly determined value, the
lessee shall be liable for the difference,
if any, between royalty payments made
based upon the value it has used and
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the royalty payments that are due based
upon the value established by ONRR.
The lessee shall also be liable for
interest computed pursuant to
§ 1218.202 of this chapter. If the lessee
is entitled to a credit, ONRR will
provide instructions for the taking of
that credit.
(f) The lessee may request a value
determination from ONRR. In that
event, the lessee shall propose to ONRR
a value determination method, and may
use that method in determining value
for royalty purposes until ONRR issues
its decision. The lessee shall submit all
available data relevant to its proposal.
The ONRR shall expeditiously
determine the value based upon the
lessee’s proposal and any additional
information ONRR deems necessary.
That determination shall remain
effective for the period stated therein.
After ONRR issues its determination,
the lessee shall make the adjustments in
accordance with paragraph (e) of this
section.
(g) Notwithstanding any other
provisions of this section, under no
circumstances shall the value for royalty
purposes be less than the gross proceeds
accruing to the lessee for the disposition
of produced coal less applicable
provisions of paragraph (b)(5) of this
section and less applicable allowances
determined pursuant to §§ 1206.258
through 1206.262 and 1206.265 of this
subpart.
(h) The lessee is required to place coal
in marketable condition at no cost to the
Federal Government. Where the value
established under this section is
determined by a lessee’s gross proceeds,
that value shall be increased to the
extent that the gross proceeds has been
reduced because the purchaser, or any
other person, is providing certain
services, the cost of which ordinarily is
the responsibility of the lessee to place
the coal in marketable condition.
(i) Value shall be based on the highest
price a prudent lessee can receive
through legally enforceable claims
under its contract. Absent contract
revision or amendment, if the lessee
fails to take proper or timely action to
receive prices or benefits to which it is
entitled, it must pay royalty at a value
based upon that obtainable price or
benefit. Contract revisions or
amendments shall be in writing and
signed by all parties to an arm’s-length
contract, and may be retroactively
applied to value for royalty purposes for
a period not to exceed two years, unless
ONRR approves a longer period. If the
lessee makes timely application for a
price increase allowed under its
contract but the purchaser refuses, and
the lessee takes reasonable measures,
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which are documented, to force
purchaser compliance, the lessee will
owe no additional royalties unless or
until monies or consideration resulting
from the price increase are received.
This paragraph shall not be construed to
permit a lessee to avoid its royalty
payment obligation in situations where
a purchaser fails to pay, in whole or in
part or timely, for a quantity of coal.
(j) Notwithstanding any provision in
these regulations to the contrary, no
review, reconciliation, monitoring, or
other like process that results in a
redetermination by ONRR of value
under this section shall be considered
final or binding as against the Federal
Government or its beneficiaries until the
audit period is formally closed.
(k) Certain information submitted to
ONRR to support valuation proposals,
including transportation, coal washing,
or other allowances under § 1206.265 of
this subpart, is exempted from
disclosure by the Freedom of
Information Act, 5 U.S.C. 522. Any data
specified by the Act to be privileged,
confidential, or otherwise exempt shall
be maintained in a confidential manner
in accordance with applicable law and
regulations. All requests for information
about determinations made under this
part are to be submitted in accordance
with the Freedom of Information Act
regulation of the Department of the
Interior, 43 CFR part 2.
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§ 1206.258
Washing allowances—general.
(a) For ad valorem leases subject to
§ 1206.257 of this subpart, ONRR shall,
as authorized by this section, allow a
deduction in determining value for
royalty purposes for the reasonable,
actual costs incurred to wash coal,
unless the value determined pursuant to
§ 1206.257 of this subpart was based
upon like-quality unwashed coal. Under
no circumstances will the authorized
washing allowance and the
transportation allowance reduce the
value for royalty purposes to zero.
(b) If ONRR determines that a lessee
has improperly determined a washing
allowance authorized by this section,
then the lessee shall be liable for any
additional royalties, plus interest
determined in accordance with
§ 1218.202 of this chapter, or shall be
entitled to a credit without interest.
(c) Lessees shall not
disproportionately allocate washing
costs to Federal leases.
(d) No cost normally associated with
mining operations and which are
necessary for placing coal in marketable
condition shall be allowed as a cost of
washing.
(e) Coal washing costs shall only be
recognized as allowances when the
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washed coal is sold and royalties are
reported and paid.
§ 1206.259 Determination of washing
allowances.
(a) Arm’s-length contracts. (1) For
washing costs incurred by a lessee
under an arm’s-length contract, the
washing allowance shall be the
reasonable actual costs incurred by the
lessee for washing the coal under that
contract, subject to monitoring, review,
audit, and possible future adjustment.
The lessee shall have the burden of
demonstrating that its contract is arm’slength. ONRR’s prior approval is not
required before a lessee may deduct
costs incurred under an arm’s-length
contract. The lessee must claim a
washing allowance by reporting it as a
separate line entry on the form ONRR–
4430.
(2) In conducting reviews and audits,
ONRR will examine whether the
contract reflects more than the
consideration actually transferred either
directly or indirectly from the lessee to
the washer for the washing. If the
contract reflects more than the total
consideration paid, then the ONRR may
require that the washing allowance be
determined in accordance with
paragraph (b) of this section.
(3) If ONRR determines that the
consideration paid pursuant to an arm’slength washing contract does not reflect
the reasonable value of the washing
because of misconduct by or between
the contracting parties, or because the
lessee otherwise has breached its duty
to the lessor to market the production
for the mutual benefit of the lessee and
the lessor, then ONRR shall require that
the washing allowance be determined in
accordance with paragraph (b) of this
section. When ONRR determines that
the value of the washing may be
unreasonable, ONRR will notify the
lessee and give the lessee an
opportunity to provide written
information justifying the lessee’s
washing costs.
(4) Where the lessee’s payments for
washing under an arm’s-length contract
are not based on a dollar-per-unit basis,
the lessee shall convert whatever
consideration is paid to a dollar value
equivalent. Washing allowances shall be
expressed as a cost per ton of coal
washed.
(b) Non-arm’s-length or no contract.
(1) If a lessee has a non-arm’s-length
contract or has no contract, including
those situations where the lessee
performs washing for itself, the washing
allowance will be based upon the
lessee’s reasonable actual costs. All
washing allowances deducted under a
non-arm’s-length or no contract
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situation are subject to monitoring,
review, audit, and possible future
adjustment. The lessee must claim a
washing allowance by reporting it as a
separate line entry on the form ONRR–
4430. When necessary or appropriate,
ONRR may direct a lessee to modify its
estimated or actual washing allowance.
(2) The washing allowance for nonarm’s-length or no contract situations
shall be based upon the lessee’s actual
costs for washing during the reported
period, including operating and
maintenance expenses, overhead, and
either depreciation and a return on
undepreciated capital investment in
accordance with paragraph (b)(2)(iv) (A)
of this section, or a cost equal to the
depreciable investment in the wash
plant multiplied by the rate of return in
accordance with paragraph (b)(2)(iv)(B)
of this section. Allowable capital costs
are generally those for depreciable fixed
assets (including costs of delivery and
installation of capital equipment) which
are an integral part of the wash plant.
(i) Allowable operating expenses
include: Operations supervision and
engineering; operations labor; fuel;
utilities; materials; ad valorem property
taxes, rent; supplies; and any other
directly allocable and attributable
operating expense which the lessee can
document.
(ii) Allowable maintenance expenses
include: Maintenance of the wash plant;
maintenance of equipment;
maintenance labor; and other directly
allocable and attributable maintenance
expenses which the lessee can
document.
(iii) Overhead attributable and
allocable to the operation and
maintenance of the wash plant is an
allowable expense. State and Federal
income taxes and severance taxes,
including royalties, are not allowable
expenses.
(iv) A lessee may use either paragraph
(b)(2)(iv)(A) or (B) of this section. After
a lessee has elected to use either method
for a wash plant, the lessee may not
later elect to change to the other
alternative without approval of the
ONRR.
(A) To compute depreciation, the
lessee may elect to use either a straightline depreciation method based on the
life of equipment or on the life of the
reserves which the wash plant services,
whichever is appropriate, or a unit of
production method. After an election is
made, the lessee may not change
methods without ONRR approval. A
change in ownership of a wash plant
shall not alter the depreciation schedule
established by the original operator/
lessee for purposes of the allowance
calculation. With or without a change in
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ownership, a wash plant shall be
depreciated only once. Equipment shall
not be depreciated below a reasonable
salvage value.
(B) ONRR shall allow as a cost an
amount equal to the allowable capital
investment in the wash plant multiplied
by the rate of return determined
pursuant to paragraph (b)(2)(v) of this
section. No allowance shall be provided
for depreciation. This alternative shall
apply only to plants first placed in
service or acquired after March 1, 1989.
(v) The rate of return must be the
industrial rate associated with Standard
and Poor’s BBB rating. The rate of return
must be the monthly average rate as
published in Standard and Poor’s Bond
Guide for the first month for which the
allowance is applicable. The rate must
be redetermined at the beginning of
each subsequent calendar year.
(3) The washing allowance for coal
shall be determined based on the
lessee’s reasonable and actual cost of
washing the coal. The lessee may not
take an allowance for the costs of
washing lease production that is not
royalty bearing.
(c) Reporting requirements—(1)
Arm’s-length contracts. (i) The lessee
must notify ONRR of an allowance
based on incurred costs by using a
separate line entry on the form ONRR–
4430.
(ii) ONRR may require that a lessee
submit arm’s-length washing contracts
and related documents. Documents
shall be submitted within a reasonable
time, as determined by ONRR.
(2) Non-arm’s-length or no contract.
(i) The lessee must notify ONRR of an
allowance based on the incurred costs
by using a separate line entry on the
form ONRR–4430.
(ii) For new washing facilities or
arrangements, the lessee’s initial
washing deduction shall include
estimates of the allowable coal washing
costs for the applicable period. Cost
estimates shall be based upon the most
recently available operations data for
the washing system or, if such data are
not available, the lessee shall use
estimates based upon industry data for
similar washing systems.
(iii) Upon request by ONRR, the lessee
shall submit all data used to prepare the
allowance deduction. The data shall be
provided within a reasonable period of
time, as determined by ONRR.
(d) Interest and assessments. (1) If a
lessee nets a washing allowance on the
form ONRR–4430, then the lessee shall
be assessed an amount up to 10 percent
of the allowance netted not to exceed
$250 per lease sales type code per sales
period.
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(2) If a lessee erroneously reports a
washing allowance which results in an
underpayment of royalties, interest shall
be paid on the amount of that
underpayment.
(3) Interest required to be paid by this
section shall be determined in
accordance with § 1218.202 of this
chapter.
(e) Adjustments. (1) If the actual coal
washing allowance is less than the
amount the lessee has taken on form
ONRR–4430 for each month during the
allowance reporting period, the lessee
shall pay additional royalties due plus
interest computed under § 1218.202 of
this chapter from the date when the
lessee took the deduction to the date the
lessee repays the difference to ONRR. If
the actual washing allowance is greater
than the amount the lessee has taken on
form ONRR–4430 for each month during
the allowance reporting period, the
lessee shall be entitled to a credit
without interest.
(2) The lessee must submit a corrected
form ONRR–4430 to reflect actual costs,
together with any payment, in
accordance with instructions provided
by ONRR.
(f) Other washing cost determinations.
The provisions of this section shall
apply to determine washing costs when
establishing value using a net-back
valuation procedure or any other
procedure that requires deduction of
washing costs.
§ 1206.260
Allocation of washed coal.
(a) When coal is subjected to washing,
the washed coal must be allocated to the
leases from which it was extracted.
(b) When the net output of coal from
a washing plant is derived from coal
obtained from only one lease, the
quantity of washed coal allocable to the
lease will be based on the net output of
the washing plant.
(c) When the net output of coal from
a washing plant is derived from coal
obtained from more than one lease,
unless determined otherwise by BLM,
the quantity of net output of washed
coal allocable to each lease will be
based on the ratio of measured
quantities of coal delivered to the
washing plant and washed from each
lease compared to the total measured
quantities of coal delivered to the
washing plant and washed.
§ 1206.261
general.
Transportation allowances—
(a) For ad valorem leases subject to
§ 1206.257 of this subpart, where the
value for royalty purposes has been
determined at a point remote from the
lease or mine, ONRR shall, as
authorized by this section, allow a
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deduction in determining value for
royalty purposes for the reasonable,
actual costs incurred to:
(1) Transport the coal from a Federal
lease to a sales point which is remote
from both the lease and mine; or
(2) 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. In-mine
transportation costs shall not be
included in the transportation
allowance.
(b) Under no circumstances will the
authorized washing allowance and the
transportation allowance reduce the
value for royalty purposes to zero.
(c)(1) When coal transported from a
mine to a wash plant is eligible for a
transportation allowance in accordance
with this section, the lessee is not
required to allocate transportation costs
between the quantity of clean coal
output and the rejected waste material.
The transportation allowance shall be
authorized for the total production
which is transported. Transportation
allowances shall be expressed as a cost
per ton of cleaned coal transported.
(2) For coal that is not washed at a
wash plant, the transportation
allowance shall be authorized for the
total production which is transported.
Transportation allowances shall be
expressed as a cost per ton of coal
transported.
(3) Transportation costs shall only be
recognized as allowances when the
transported coal is sold and royalties are
reported and paid.
(d) If, after a review and/or audit,
ONRR determines that a lessee has
improperly determined a transportation
allowance authorized by this section,
then the lessee shall pay any additional
royalties, plus interest, determined in
accordance with § 1218.202 of this
chapter, or shall be entitled to a credit,
without interest.
(e) Lessees shall not
disproportionately allocate
transportation costs to Federal leases.
§ 1206.262 Determination of
transportation allowances.
(a) Arm’s-length contracts. (1) For
transportation costs incurred by a lessee
pursuant to an arm’s-length contract, the
transportation allowance shall be the
reasonable, actual costs incurred by the
lessee for transporting the coal under
that contract, subject to monitoring,
review, audit, and possible future
adjustment. The lessee shall have the
burden of demonstrating that its
contract is arm’s-length. The lessee must
claim a transportation allowance by
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reporting it as a separate line entry on
the form ONRR–4430.
(2) In conducting reviews and audits,
ONRR will examine whether the
contract reflects more than the
consideration actually transferred either
directly or indirectly from the lessee to
the transporter for the transportation. If
the contract reflects more than the total
consideration paid, then the ONRR may
require that the transportation
allowance be determined in accordance
with paragraph (b) of this section.
(3) If ONRR determines that the
consideration paid pursuant to an arm’slength transportation contract does not
reflect the reasonable value of the
transportation because of misconduct by
or between the contracting parties, or
because the lessee otherwise has
breached its duty to the lessor to market
the production for the mutual benefit of
the lessee and the lessor, then ONRR
shall require that the transportation
allowance be determined in accordance
with paragraph (b) of this section. When
ONRR determines that the value of the
transportation may be unreasonable,
ONRR will notify the lessee and give the
lessee an opportunity to provide written
information justifying the lessee’s
transportation costs.
(4) Where the lessee’s payments for
transportation under an arm’s-length
contract are not based on a dollar-perunit basis, the lessee shall convert
whatever consideration is paid to a
dollar value equivalent for the purposes
of this section.
(b) Non-arm’s-length or no contract—
(1) If a lessee has a non-arm’s-length
contract or has no contract, including
those situations where the lessee
performs transportation services for
itself, the transportation allowance will
be based upon the lessee’s reasonable
actual costs. All transportation
allowances deducted under a non-arm’slength or no contract situation are
subject to monitoring, review, audit, and
possible future adjustment. The lessee
must claim a transportation allowance
by reporting it as a separate line entry
on the form ONRR–4430. When
necessary or appropriate, ONRR may
direct a lessee to modify its estimated or
actual transportation allowance
deduction.
(2) The transportation allowance for
non-arm’s-length or no-contract
situations shall be based upon the
lessee’s actual costs for transportation
during the reporting period, including
operating and maintenance expenses,
overhead, and either depreciation and a
return on undepreciated capital
investment in accordance with
paragraph (b)(2)(iv)(A) of this section, or
a cost equal to the depreciable
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investment in the transportation system
multiplied by the rate of return in
accordance with paragraph (b)(2)(iv)(B)
of this section. Allowable capital costs
are generally those for depreciable fixed
assets (including costs of delivery and
installation of capital equipment) which
are an integral part of the transportation
system.
(i) Allowable operating expenses
include: Operations supervision and
engineering; operations labor; fuel;
utilities; materials; ad valorem property
taxes; rent; supplies; and any other
directly allocable and attributable
operating expense which the lessee can
document.
(ii) Allowable maintenance expenses
include: Maintenance of the
transportation system; maintenance of
equipment; maintenance labor; and
other directly allocable and attributable
maintenance expenses which the lessee
can document.
(iii) Overhead attributable and
allocable to the operation and
maintenance of the transportation
system is an allowable expense. State
and Federal income taxes and severance
taxes and other fees, including royalties,
are not allowable expenses.
(iv) A lessee may use either paragraph
(b)(2)(iv)(A) or (B) of this section. After
a lessee has elected to use either method
for a transportation system, the lessee
may not later elect to change to the
other alternative without approval of
ONRR.
(A) To compute depreciation, the
lessee may elect to use either a straightline depreciation method based on the
life of equipment or on the life of the
reserves which the transportation
system services, whichever is
appropriate, or a unit of production
method. After an election is made, the
lessee may not change methods without
ONRR approval. A change in ownership
of a transportation system shall not alter
the depreciation schedule established
by the original transporter/lessee for
purposes of the allowance calculation.
With or without a change in ownership,
a transportation system shall be
depreciated only once. Equipment shall
not be depreciated below a reasonable
salvage value.
(B) ONRR shall allow as a cost an
amount equal to the allowable capital
investment in the transportation system
multiplied by the rate of return
determined pursuant to paragraph
(b)(2)(B)(v) of this section. No allowance
shall be provided for depreciation. This
alternative shall apply only to
transportation facilities first placed in
service or acquired after March 1, 1989.
(v) The rate of return must be the
industrial rate associated with Standard
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and Poor’s BBB rating. The rate of return
must be the monthly average rate as
published in Standard and Poor’s Bond
Guide for the first month for which the
allowance is applicable. The rate must
be redetermined at the beginning of
each subsequent calendar year.
(3) A lessee may apply to ONRR for
exception from the requirement that it
compute actual costs in accordance with
paragraphs (b)(1) and (2) of this section.
ONRR will grant the exception only if
the lessee has a rate for the
transportation approved by a Federal
agency or by a State regulatory agency
(for Federal leases). ONRR shall deny
the exception request if it determines
that the rate is excessive as compared to
arm’s-length transportation charges by
systems, owned by the lessee or others,
providing similar transportation
services in that area. If there are no
arm’s-length transportation charges,
ONRR shall deny the exception request
if:
(i) No Federal or State regulatory
agency costs analysis exists and the
Federal or State regulatory agency, as
applicable, has declined to investigate
under ONRR timely objections upon
filing; and
(ii) The rate significantly exceeds the
lessee’s actual costs for transportation as
determined under this section.
(c) Reporting requirements—(1)
Arm’s-length contracts. (i) The lessee
must notify ONRR of an allowance
based on incurred costs by using a
separate line entry on the form ONRR–
4430.
(ii) ONRR may require that a lessee
submit arm’s-length transportation
contracts, production agreements,
operating agreements, and related
documents. Documents shall be
submitted within a reasonable time, as
determined by ONRR.
(2) Non-arm’s-length or no contract—
(i) The lessee must notify ONRR of an
allowance based on the incurred costs
by using a separate line entry on form
ONRR–4430.
(ii) For new transportation facilities or
arrangements, the lessee’s initial
deduction shall include estimates of the
allowable coal transportation costs for
the applicable period. Cost estimates
shall be based upon the most recently
available operations data for the
transportation system or, if such data
are not available, the lessee shall use
estimates based upon industry data for
similar transportation systems.
(iii) Upon request by ONRR, the lessee
shall submit all data used to prepare the
allowance deduction. The data shall be
provided within a reasonable period of
time, as determined by ONRR.
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(iv) If the lessee is authorized to use
its Federal- or State-agency-approved
rate as its transportation cost in
accordance with paragraph (b)(3) of this
section, it shall follow the reporting
requirements of paragraph (c)(1) of this
section.
(d) Interest and assessments. (1) If a
lessee nets a transportation allowance
on form ONRR–4430, the lessee shall be
assessed an amount of up to 10 percent
of the allowance netted not to exceed
$250 per lease sales type code per sales
period.
(2) If a lessee erroneously reports a
transportation allowance which results
in an underpayment of royalties,
interest shall be paid on the amount of
that underpayment.
(3) Interest required to be paid by this
section shall be determined in
accordance with § 1218.202 of this
chapter.
(e) Adjustments. (1) If the actual coal
transportation allowance is less than the
amount the lessee has taken on form
ONRR–4430 for each month during the
allowance reporting period, the lessee
shall pay additional royalties due plus
interest computed under § 1218.202 of
this chapter from the date when the
lessee took the deduction to the date the
lessee repays the difference to ONRR. If
the actual transportation allowance is
greater than amount the lessee has taken
on form ONRR–4430 for each month
during the allowance reporting period,
the lessee shall be entitled to a credit
without interest.
(2) The lessee must submit a corrected
form ONRR–4430 to reflect actual costs,
together with any payments, in
accordance with instructions provided
by ONRR.
(f) Other transportation cost
determinations. The provisions of this
section shall apply to determine
transportation costs when establishing
value using a net-back valuation
procedure or any other procedure that
requires deduction of transportation
costs.
§ 1206.263
[Reserved]
§ 1206.265 Value enhancement of
marketable coal.
If, prior to use, sale, or other
disposition, the lessee enhances the
value of coal after the coal has been
placed in marketable condition in
accordance with § 1206.257(h) of this
subpart, the lessee shall notify ONRR
that such processing is occurring or will
occur. The value of that production
shall be determined as follows:
(a) A value established for the
feedstock coal in marketable condition
by application of the provisions of
§ 1206.257(c)(2)(i) through (iv) of this
subpart; or,
(b) In the event that a value cannot be
established in accordance with
paragraph (a) of this section, then the
value of production will be determined
in accordance with § 1206.257(c)(2)(v)
of this subpart and the value shall be the
lessee’s gross proceeds accruing from
the disposition of the enhanced product,
reduced by ONRR-approved processing
costs and procedures including a rate of
return on investment equal to two times
the Standard and Poor’s BBB bond rate
applicable under § 1206.259(b)(2)(v) of
this subpart.
■ 9. Revise subpart J to read as follows:
Subpart J—Indian Coal
Sec.
1206.450 Purpose and scope.
1206.451 Definitions.
1206.452 Coal subject to royalties—general
provisions.
1206.453 Quality and quantity
measurement standards for reporting and
paying royalties.
1206.454 Point of royalty determination.
1206.455 Valuation standards for cents-perton leases.
1206.456 Valuation standards for ad
valorem leases.
1206.457 Washing allowances—general.
1206.458 Determination of washing
allowances.
1206.459 Allocation of washed coal.
1206.460 Transportation allowances—
general.
1206.461 Determination of transportation
allowances.
1206.462 [Reserved]
1206.463 In-situ and surface gasification
and liquefaction operations.
1206.464 Value enhancement of marketable
coal.
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§ 1206.264 In-situ and surface gasification
and liquefaction operations.
Subpart J—Indian Coal
If an ad valorem Federal coal lease is
developed by in-situ or surface
gasification or liquefaction technology,
the lessee shall propose the value of
coal for royalty purposes to ONRR. The
ONRR will review the lessee’s proposal
and issue a value determination. The
lessee may use its proposed value until
ONRR issues a value determination.
(a) This subpart prescribes the
procedures to establish the value, for
royalty purposes, of all coal from Indian
Tribal and allotted leases (except leases
on the Osage Indian Reservation, Osage
County, Oklahoma).
(b) If the specific provisions of any
statute, treaty, or settlement agreement
between the Indian lessor and a lessee
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§ 1206.450
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36981
resulting from administrative or judicial
litigation, or any coal lease subject to
the requirements of this subpart, are
inconsistent with any regulation in this
subpart, then the statute, treaty, lease
provision, or settlement shall govern to
the extent of that inconsistency.
(c) All royalty payments are subject to
later audit and adjustment.
(d) The regulations in this subpart are
intended to ensure that the trust
responsibilities of the United States
with respect to the administration of
Indian coal leases are discharged in
accordance with the requirements of the
governing mineral leasing laws, treaties,
and lease terms.
§ 1206.451
Definitions.
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.
Allowance means an approved, or an
ONRR-initially accepted deduction in
determining value for royalty purposes.
Coal washing allowance means an
allowance for the reasonable, actual
costs incurred by the lessee for coal
washing, or an approved or ONRRinitially accepted deduction for the
costs of washing coal, determined
pursuant to this subpart. Transportation
allowance means an allowance for the
reasonable, actual costs incurred by the
lessee for moving coal to a point of sale
or point of delivery remote from both
the lease and mine or wash plant, or an
approved ONRR-initially accepted
deduction for costs of such
transportation, determined pursuant to
this subpart.
Area means a geographic region in
which coal has 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 that has been
arrived at in the marketplace between
independent, nonaffiliated persons with
opposing economic interests regarding
that contract. For purposes of this
subpart, two persons are affiliated if one
person controls, is controlled by, or is
under common control with another
person. For purposes of this subpart,
based on the instruments of ownership
of the voting securities of an entity, or
based on other forms of ownership:
Ownership in excess of 50 percent
constitutes control; ownership of 10
through 50 percent creates a
presumption of control; and ownership
of less than 10 percent creates a
presumption of noncontrol which
ONRR may rebut if it demonstrates
actual or legal control, including the
existence of interlocking directorates.
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Notwithstanding any other provisions of
this subpart, contracts between
relatives, either by blood or by marriage,
are not arm’s-length contracts. ONRR
may require the lessee to certify
ownership control. To be considered
arm’s-length for any production month,
a contract must meet the requirements
of this definition for that production
month, as well as when the contract was
executed.
Audit means a review, conducted in
accordance with generally accepted
accounting and auditing standards, of
royalty payment compliance activities
of lessees or other interest holders who
pay royalties, rents, or bonuses on
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.
Coal means coal of all ranks from
lignite through anthracite.
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).
Contract means any oral or written
agreement, including amendments or
revisions thereto, between two or more
persons and enforceable by law that
with due consideration creates an
obligation.
Gross proceeds (for royalty payment
purposes) means the total monies and
other consideration accruing to a coal
lessee for the production and
disposition of the coal produced. Gross
proceeds includes, but is not limited to,
payments to the lessee for certain
services such as crushing, sizing,
screening, storing, mixing, loading,
treatment with substances including
chemicals or oils, and other preparation
of the coal to the extent that the lessee
is obligated to perform them at no cost
to the Indian lessor. Gross proceeds, as
applied to coal, also includes but is not
limited to reimbursements for royalties,
taxes or fees, and other reimbursements.
Tax reimbursements are part of the gross
proceeds accruing to a lessee even
though the Indian royalty interest may
be exempt from taxation. Monies and
other consideration, including the forms
of consideration identified in this
paragraph, to which a lessee is
contractually or legally entitled but
which it does not seek to collect through
reasonable efforts are also part of gross
proceeds.
Indian allottee means any Indian for
whom land or an interest in land is held
in trust by the United States or who
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holds title subject to Federal restriction
against alienation.
Indian Tribe means any Indian Tribe,
band, nation, pueblo, community,
rancheria, colony, or other group of
Indians for which any land or interest
in land is held in trust by the United
States or which is subject to Federal
restriction against alienation.
Lease means any contract, profit-share
arrangement, joint venture, or other
agreement issued or approved by the
United States for an Indian coal
resource under a mineral leasing law
that authorizes exploration for,
development or extraction of, or
removal of coal—or the land covered by
that authorization, whichever is
required by the context.
Lessee means any person to whom the
Indian Tribe or an Indian allottee issues
a lease, and any person who has been
assigned an obligation to make royalty
or other payments required by the lease.
This includes any person who has an
interest in a lease as well as an operator
or payor who has no interest in the lease
but who has assumed the royalty
payment responsibility.
Like-quality coal means coal that has
similar chemical and physical
characteristics.
Marketable condition means coal that
is sufficiently free from impurities and
otherwise in a condition that it will be
accepted by a purchaser under a sales
contract typical for that area.
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.
Net-back method means a method for
calculating market value of coal at the
lease or mine. Under this method, costs
of transportation, washing, handling,
etc., are deducted from the ultimate
proceeds received for the coal at the first
point at which reasonable values for the
coal may be determined by a sale
pursuant to an arm’s-length contract or
by comparison to other sales of coal, to
ascertain value at the mine.
Net output means the quantity of
washed coal that a washing plant
produces.
ONRR means the Office of Natural
Resources Revenue of the Department of
the Interior.
Person means by individual, firm,
corporation, association, partnership,
consortium, or joint venture.
Sales type code means the contract
type or general disposition (e.g., arm’slength or non-arm’s-length) of
production from the lease. The sales
type code applies to the sales contract,
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or other disposition, and not to the
arm’s-length or non-arm’s-length nature
of a transportation or washing
allowance.
Spot market price means the price
received under any sales transaction
when planned or actual deliveries span
a short period of time, usually not
exceeding one year.
§ 1206.452 Coal subject to royalties—
general provisions.
(a) All coal (except coal unavoidably
lost as determined by BLM pursuant to
43 CFR group 3400) from an Indian
lease subject to this part is subject to
royalty. This includes coal used, sold, or
otherwise disposed of by the lessee on
or off the lease.
(b) If a lessee receives compensation
for unavoidably lost coal through
insurance coverage or other
arrangements, royalties at the rate
specified in the lease are to be paid on
the amount of compensation received
for the coal. No royalty is due on
insurance compensation received by the
lessee for other losses.
(c) If waste piles or slurry ponds are
reworked to recover coal, the lessee
shall pay royalty at the rate specified in
the lease at the time the recovered coal
is used, sold, or otherwise finally
disposed of. The royalty rate shall be
that rate applicable to the production
method used to initially mine coal in
the waste pile or slurry pond; i.e.,
underground mining method or surface
mining method. Coal in waste pits or
slurry ponds initially mined from
Indian leases shall be allocated to such
leases regardless of whether it is stored
on Indian lands. The lessee shall
maintain accurate records to determine
to which individual Indian lease coal in
the waste pit or slurry pond should be
allocated. However, nothing in this
section requires payment of a royalty on
coal for which a royalty has already
been paid.
§ 1206.453 Quality and quantity
measurement standards for reporting and
paying royalties.
For all leases subject to this subpart,
the quantity of coal on which royalty is
due shall be measured in short tons (of
2,000 pounds each) by methods
prescribed by the BLM. Coal quantity
information will be reported on
appropriate forms required under 30
CFR part 1210—Forms and Reports.
§ 1206.454
Point of royalty determination.
(a) For all leases subject to this
subpart, royalty shall be computed on
the basis of the quantity and quality of
Indian coal in marketable condition
measured at the point of royalty
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measurement as determined jointly by
BLM and ONRR.
(b) Coal produced and added to
stockpiles or inventory does not require
payment of royalty until such coal is
later used, sold, or otherwise finally
disposed of. ONRR may ask BLM or BIA
to increase the lease bond to protect the
lessor’s interest when BLM determines
that stockpiles or inventory become
excessive so as to increase the risk of
degradation of the resource.
(c) The lessee shall pay royalty at a
rate specified in the lease at the time the
coal is used, sold, or otherwise finally
disposed of, unless otherwise provided
for at § 1206.455(d) of this subpart.
§ 1206.455 Valuation standards for centsper-ton leases.
(a) This section is applicable to coal
leases on Indian Tribal and allotted
Indian lands (except leases on the Osage
Indian Reservation, Osage County,
Oklahoma) which provide for the
determination of royalty on a cents-perton (or other quantity) basis.
(b) The royalty for coal from leases
subject to this section shall be based on
the dollar rate per ton prescribed in the
lease. That dollar rate shall be
applicable to the actual quantity of coal
used, sold, or otherwise finally disposed
of, including coal which is avoidably
lost as determined by BLM pursuant to
43 CFR part 3400.
(c) For leases subject to this section,
there shall be no allowances for
transportation, removal of impurities,
coal washing, or any other processing or
preparation of the coal.
(d) When a coal lease is readjusted
pursuant to 43 CFR part 3400 and the
royalty valuation method changes from
a cents-per-ton basis to an ad valorem
basis, coal which is produced prior to
the effective date of readjustment and
sold or used within 30 days of the
effective date of readjustment shall be
valued pursuant to this section. All coal
that is not used, sold, or otherwise
finally disposed of within 30 days after
the effective date of readjustment shall
be valued pursuant to the provisions of
§ 1206.456 of this subpart, and royalties
shall be paid at the royalty rate specified
in the readjusted lease.
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§ 1206.456 Valuation standards for ad
valorem leases.
(a) This section is applicable to coal
leases on Indian Tribal and allotted
Indian lands (except leases on the Osage
Indian Reservation, Osage County,
Oklahoma) which provide for the
determination of royalty as a percentage
of the amount of value of coal (ad
valorem). The value for royalty purposes
of coal from such leases shall be the
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value of coal determined pursuant to
this section, less applicable coal
washing allowances and transportation
allowances determined pursuant to
§§ 1206.457 through 1206.461 of this
subpart, or any allowance authorized by
§ 1206.464 of this subpart. The royalty
due shall be equal to the value for
royalty purposes multiplied by the
royalty rate in the lease.
(b)(1) The value of coal that is sold
pursuant to an arm’s-length contract
shall be the gross proceeds accruing to
the lessee, except as provided in
paragraphs (b)(2), (3), and (5) of this
section. The lessee shall have the
burden of demonstrating that its
contract is arm’s-length. The value
which the lessee reports, for royalty
purposes, is subject to monitoring,
review, and audit.
(2) In conducting reviews and audits,
ONRR will examine whether the
contract reflects the total consideration
actually transferred either directly or
indirectly from the buyer to the seller
for the coal produced. If the contract
does not reflect the total consideration,
then ONRR may require that the coal
sold pursuant to that contract be valued
in accordance with paragraph (c) of this
section. Value may not be based on less
than the gross proceeds accruing to the
lessee for the coal production, including
the additional consideration.
(3) If ONRR determines that the gross
proceeds accruing to the lessee pursuant
to an arm’s-length contract do not reflect
the reasonable value of the production
because of misconduct by or between
the contracting parties, or because the
lessee otherwise has breached its duty
to the lessor to market the production
for the mutual benefit of the lessee and
the lessor, then ONRR shall require that
the coal production be valued pursuant
to paragraphs (c)(2)(ii), (iii), (iv), or (v)
of this section, and in accordance with
the notification requirements of
paragraph (d)(3) of this section. When
ONRR determines that the value may be
unreasonable, ONRR will notify the
lessee and give the lessee an
opportunity to provide written
information justifying the lessee’s
reported coal value.
(4) ONRR may require a lessee to
certify that its arm’s-length contract
provisions include all of the
consideration to be paid by the buyer,
either directly or indirectly, for the coal
production.
(5) The value of production for royalty
purposes shall not include payments
received by the lessee pursuant to a
contract which the lessee demonstrates,
to ONRR’s satisfaction, were not part of
the total consideration paid for the
purchase of coal production.
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(c)(1) The value of coal from leases
subject to this section and which is not
sold pursuant to an arm’s-length
contract shall be determined in
accordance with this section.
(2) If the value of the coal cannot be
determined pursuant to paragraph (b) of
this section, then the value shall be
determined through application of other
valuation criteria. The criteria shall be
considered in the following order, and
the value shall be based upon the first
applicable criterion:
(i) The gross proceeds accruing to the
lessee pursuant to a sale under its nonarm’s-length contract (or other
disposition of produced coal by other
than an arm’s-length contract), provided
that those gross proceeds are within the
range of the gross proceeds derived
from, or paid under, comparable arm’slength contracts between buyers and
sellers neither of whom is affiliated with
the lessee for sales, purchases, or other
dispositions of like-quality coal
produced in the area. In evaluating the
comparability of arm’s-length contracts
for the purposes of these regulations, the
following factors shall be considered:
Price, time of execution, duration,
market or markets served, terms, quality
of coal, quantity, and such other factors
as may be appropriate to reflect the
value of the coal;
(ii) Prices reported for that coal to a
public utility commission;
(iii) Prices reported for that coal to the
Energy Information Administration of
the Department of Energy;
(iv) Other relevant matters including,
but not limited to, published or publicly
available spot market prices, or
information submitted by the lessee
concerning circumstances unique to a
particular lease operation or the
salability of certain types of coal;
(v) If a reasonable value cannot be
determined using paragraphs (c)(2)(i),
(ii), (iii), or (iv) of this section, then a
net-back method or any other reasonable
method shall be used to determine
value.
(3) When the value of coal is
determined pursuant to paragraph (c)(2)
of this section, that value determination
shall be consistent with the provisions
contained in paragraph (b)(5) of this
section.
(d)(1) Where the value is determined
pursuant to paragraph (c) of this section,
that value does not require ONRR’s
prior approval. However, the lessee
shall retain all data relevant to the
determination of royalty value. Such
data shall be subject to review and
audit, and ONRR will direct a lessee to
use a different value if it determines that
the reported value is inconsistent with
the requirements of these regulations.
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(2) An Indian lessee will make
available upon request to the authorized
ONRR or Indian representatives, or to
the Inspector General of the Department
of the Interior or other persons
authorized to receive such information,
arm’s-length sales and sales quantity
data for like-quality coal sold,
purchased, or otherwise obtained by the
lessee from the area.
(3) A lessee shall notify ONRR if it has
determined value pursuant to
paragraphs (c)(2)(ii), (iii), (iv), or (v) of
this section. The notification shall be by
letter to the Director for Office of
Natural Resources Revenue or his/her
designee. The letter shall identify the
valuation method to be used and
contain a brief description of the
procedure to be followed. The
notification required by this section is a
one-time notification due no later than
the month the lessee first reports
royalties on the form ONRR–4430 using
a valuation method authorized by
paragraphs (c)(2)(ii), (iii), (iv), or (v) of
this section, and each time there is a
change in a method under paragraphs
(c)(2)(iv) or (v) of this section.
(e) If ONRR determines that a lessee
has not properly determined value, the
lessee shall be liable for the difference,
if any, between royalty payments made
based upon the value it has used and
the royalty payments that are due based
upon the value established by ONRR.
The lessee shall also be liable for
interest computed pursuant to 30 CFR
1218.202. If the lessee is entitled to a
credit, ONRR will provide instructions
for the taking of that credit.
(f) The lessee may request a value
determination from ONRR. In that
event, the lessee shall propose to ONRR
a value determination method, and may
use that method in determining value
for royalty purposes until ONRR issues
its decision. The lessee shall submit all
available data relevant to its proposal.
ONRR shall expeditiously determine the
value based upon the lessee’s proposal
and any additional information ONRR
deems necessary. That determination
shall remain effective for the period
stated therein. After ONRR issues its
determination, the lessee shall make the
adjustments in accordance with
paragraph (e) of this section.
(g) Notwithstanding any other
provisions of this section, under no
circumstances shall the value for royalty
purposes be less than the gross proceeds
accruing to the lessee for the disposition
of produced coal less applicable
provisions of paragraph (b)(5) of this
section and less applicable allowances
determined pursuant to §§ 1206.457
through 1206.461 and 1206.464 of this
subpart.
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(h) The lessee is required to place coal
in marketable condition at no cost to the
Indian lessor. Where the value
established pursuant to this section is
determined by a lessee’s gross proceeds,
that value shall be increased to the
extent that the gross proceeds has been
reduced because the purchaser, or any
other person, is providing certain
services, the cost of which ordinarily is
the responsibility of the lessee to place
the coal in marketable condition.
(i) Value shall be based on the highest
price a prudent lessee can receive
through legally enforceable claims
under its contract. Absent contract
revision or amendment, if the lessee
fails to take proper or timely action to
receive prices or benefits to which it is
entitled, it must pay royalty at a value
based upon that obtainable price or
benefit. Contract revisions or
amendments shall be in writing and
signed by all parties to an arm’s-length
contract, and may be retroactively
applied to value for royalty purposes for
a period not to exceed two years, unless
ONRR approves a longer period. If the
lessee makes timely application for a
price increase allowed under its
contract but the purchaser refuses, and
the lessee takes reasonable measures,
which are documented, to force
purchaser compliance, the lessee will
owe no additional royalties unless or
until monies or consideration resulting
from the price increase are received.
This paragraph shall not be construed to
permit a lessee to avoid its royalty
payment obligation in situations where
a purchaser fails to pay, in whole or in
part or timely, for a quantity of coal.
(j) Notwithstanding any provision in
these regulations to the contrary, no
review, reconciliation, monitoring, or
other like process that results in a
redetermination by ONRR of value
under this section shall be considered
final or binding as against the Indian
Tribes or allottees until the audit period
is formally closed.
(k) Certain information submitted to
ONRR to support valuation proposals,
including transportation, coal washing,
or other allowances pursuant to
§§ 1206.457 through 1206.461 and
1206.464 of this subpart, is exempted
from disclosure by the Freedom of
Information Act, 5 U.S.C. 522. Any data
specified by the Act to be privileged,
confidential, or otherwise exempt shall
be maintained in a confidential manner
in accordance with applicable law and
regulations. All requests for information
about determinations made under this
part are to be submitted in accordance
with the Freedom of Information Act
regulation of the Department of the
Interior, 43 CFR part 2. Nothing in this
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section is intended to limit or diminish
in any manner whatsoever the right of
an Indian lessor to obtain any and all
information as such lessor may be
lawfully entitled from ONRR or such
lessor’s lessee directly under the terms
of the lease or applicable law.
§ 1206.457
Washing allowances—general.
(a) For ad valorem leases subject to
§ 1206.456 of this subpart, ONRR shall,
as authorized by this section, allow a
deduction in determining value for
royalty purposes for the reasonable,
actual costs incurred to wash coal,
unless the value determined pursuant to
§ 1206.456 of this subpart was based
upon like-quality unwashed coal. Under
no circumstances will the authorized
washing allowance and the
transportation allowance reduce the
value for royalty purposes to zero.
(b) If ONRR determines that a lessee
has improperly determined a washing
allowance authorized by this section,
then the lessee shall be liable for any
additional royalties, plus interest
determined in accordance with
§ 1218.202 of this chapter, or shall be
entitled to a credit, without interest.
(c) Lessees shall not
disproportionately allocate washing
costs to Indian leases.
(d) No cost normally associated with
mining operations and which are
necessary for placing coal in marketable
condition shall be allowed as a cost of
washing.
(e) Coal washing costs shall only be
recognized as allowances when the
washed coal is sold and royalties are
reported and paid.
§ 1206.458 Determination of washing
allowances.
(a) Arm’s-length contracts. (1) For
washing costs incurred by a lessee
pursuant to an arm’s-length contract, the
washing allowance shall be the
reasonable actual costs incurred by the
lessee for washing the coal under that
contract, subject to monitoring, review,
audit, and possible future adjustment.
ONRR’s prior approval is not required
before a lessee may deduct costs
incurred under an arm’s-length contract.
However, before any deduction may be
taken, the lessee must submit a
completed page one of form ONRR–
4292, Coal Washing Allowance Report,
in accordance with paragraph (c)(1) of
this section. A washing allowance may
be claimed retroactively for a period of
not more than 3 months prior to the first
day of the month that form ONRR–4292
is filed with ONRR, unless ONRR
approves a longer period upon a
showing of good cause by the lessee.
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(2) In conducting reviews and audits,
ONRR will examine whether the
contract reflects more than the
consideration actually transferred either
directly or indirectly from the lessee to
the washer for the washing. If the
contract reflects more than the total
consideration paid, then ONRR may
require that the washing allowance be
determined in accordance with
paragraph (b) of this section.
(3) If ONRR determines that the
consideration paid pursuant to an arm’slength washing contract does not reflect
the reasonable value of the washing
because of misconduct by or between
the contracting parties, or because the
lessee otherwise has breached its duty
to the lessor to market the production
for the mutual benefit of the lessee and
the lessor, then ONRR shall require that
the washing allowance be determined in
accordance with paragraph (b) of this
section. When ONRR determines that
the value of the washing may be
unreasonable, ONRR will notify the
lessee and give the lessee an
opportunity to provide written
information justifying the lessee’s
washing costs.
(4) Where the lessee’s payments for
washing under an arm’s-length contract
are not based on a dollar-per-unit basis,
the lessee shall convert whatever
consideration is paid to a dollar value
equivalent. Washing allowances shall be
expressed as a cost per ton of coal
washed.
(b) Non-arm’s-length or no contract.
(1) If a lessee has a non-arm’s-length
contract or has no contract, including
those situations where the lessee
performs washing for itself, the washing
allowance will be based upon the
lessee’s reasonable actual costs. All
washing allowances deducted under a
non-arm’s-length or no contract
situation are subject to monitoring,
review, audit, and possible future
adjustment. Prior ONRR approval of
washing allowances is not required for
non-arm’s-length or no contract
situations. However, before any
estimated or actual deduction may be
taken, the lessee must submit a
completed form ONRR–4292 in
accordance with paragraph (c)(2) of this
section. A washing allowance may be
claimed retroactively for a period of not
more than 3 months prior to the first
day of the month that form ONRR–4292
is filed with ONRR, unless ONRR
approves a longer period upon a
showing of good cause by the lessee.
ONRR will monitor the allowance
deduction to ensure that deductions are
reasonable and allowable. When
necessary or appropriate, ONRR may
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direct a lessee to modify its actual
washing allowance.
(2) The washing allowance for nonarm’s-length or no contract situations
shall be based upon the lessee’s actual
costs for washing during the reported
period, including operating and
maintenance expenses, overhead, and
either depreciation and a return on
undepreciated capital investment in
accordance with paragraph (b)(2)(iv)(A)
of this section, or a cost equal to the
depreciable investment in the wash
plant multiplied by the rate of return in
accordance with paragraph (b)(2)(iv)(B)
of this section. Allowable capital costs
are generally those for depreciable fixed
assets (including costs of delivery and
installation of capital equipment) which
are an integral part of the wash plant.
(i) Allowable operating expenses
include: Operations supervision and
engineering; operations labor; fuel;
utilities; materials; ad valorem property
taxes; rent; supplies; and any other
directly allocable and attributable
operating expense which the lessee can
document.
(ii) Allowable maintenance expenses
include: Maintenance of the wash plant;
maintenance of equipment;
maintenance labor; and other directly
allocable and attributable maintenance
expenses which the lessee can
document.
(iii) Overhead attributable and
allocable to the operation and
maintenance of the wash plant is an
allowable expense. State and Federal
income taxes and severance taxes,
including royalties, are not allowable
expenses.
(iv) A lessee may use either paragraph
(b)(2)(iv)(A) or (B) of this section. After
a lessee has elected to use either method
for a wash plant, the lessee may not
later elect to change to the other
alternative without approval of ONRR.
(A) To compute depreciation, the
lessee may elect to use either a straightline depreciation method based on the
life of equipment or on the life of the
reserves which the wash plant services,
whichever is appropriate, or a unit of
production method. After an election is
made, the lessee may not change
methods without ONRR approval. A
change in ownership of a wash plant
shall not alter the depreciation schedule
established by the original operator/
lessee for purposes of the allowance
calculation. With or without a change in
ownership, a wash plant shall be
depreciated only once. Equipment shall
not be depreciated below a reasonable
salvage value.
(B) ONRR shall allow as a cost an
amount equal to the allowable capital
investment in the wash plant multiplied
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36985
by the rate of return determined
pursuant to paragraph (b)(2)(v) of this
section. No allowance shall be provided
for depreciation. This alternative shall
apply only to plants first placed in
service or acquired after March 1, 1989.
(v) The rate of return shall be the
industrial rate associated with Standard
and Poor’s BBB rating. The rate of return
shall be the monthly average rate as
published in Standard and Poor’s Bond
Guide for the first month of the
reporting period for which the
allowance is applicable and shall be
effective during the reporting period.
The rate shall be redetermined at the
beginning of each subsequent washing
allowance reporting period (which is
determined pursuant to paragraph (c)(2)
of this section).
(3) The washing allowance for coal
shall be determined based on the
lessee’s reasonable and actual cost of
washing the coal. The lessee may not
take an allowance for the costs of
washing lease production that is not
royalty bearing.
(c) Reporting requirements—(1)
Arm’s-length contracts. (i) With the
exception of those washing allowances
specified in paragraphs (c)(1)(v) and (vi)
of this section, the lessee shall submit
page one of the initial form ONRR–4292
prior to, or at the same time, as the
washing allowance determined
pursuant to an arm’s-length contract is
reported on form ONRR–4430, Solid
Minerals Production and Royalty
Report. A form ONRR–4292 received by
the end of the month that the form
ONRR–4430 is due shall be considered
to be received timely.
(ii) The initial form ONRR–4292 shall
be effective for a reporting period
beginning the month that the lessee is
first authorized to deduct a washing
allowance and shall continue until the
end of the calendar year, or until the
applicable contract or rate terminates or
is modified or amended, whichever is
earlier.
(iii) After the initial reporting period
and for succeeding reporting periods,
lessees must submit page one of form
ONRR–4292 within 3 months after the
end of the calendar year, or after the
applicable contract or rate terminates or
is modified or amended, whichever is
earlier, unless ONRR approves a longer
period (during which period the lessee
shall continue to use the allowance from
the previous reporting period).
(iv) ONRR may require that a lessee
submit arm’s-length washing contracts
and related documents. Documents
shall be submitted within a reasonable
time, as determined by ONRR.
(v) Washing allowances which are
based on arm’s-length contracts and
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which are in effect at the time these
regulations become effective will be
allowed to continue until such
allowances terminate. For the purposes
of this section, only those allowances
that have been approved by ONRR in
writing shall qualify as being in effect at
the time these regulations become
effective.
(vi) ONRR may establish, in
appropriate circumstances, reporting
requirements that are different from the
requirements of this section.
(2) Non-arm’s-length or no contract.
(i) With the exception of those washing
allowances specified in paragraphs
(c)(2)(v) and (vii) of this section, the
lessee shall submit an initial form
ONRR–4292 prior to, or at the same time
as, the washing allowance determined
pursuant to a non-arm’s-length contract
or no contract situation is reported on
form ONRR–4430, Solid Minerals
Production and Royalty Report. A form
ONRR–4292 received by the end of the
month that the form ONRR–4430 is due
shall be considered to be timely
received. The initial reporting may be
based on estimated costs.
(ii) The initial form ONRR–4292 shall
be effective for a reporting period
beginning the month that the lessee first
is authorized to deduct a washing
allowance and shall continue until the
end of the calendar year, or until the
washing under the non-arm’s-length
contract or the no contract situation
terminates, whichever is earlier.
(iii) For calendar-year reporting
periods succeeding the initial reporting
period, the lessee shall submit a
completed form ONRR–4292 containing
the actual costs for the previous
reporting period. If coal washing is
continuing, the lessee shall include on
form ONRR–4292 its estimated costs for
the next calendar year. The estimated
coal washing allowance shall be based
on the actual costs for the previous
period plus or minus any adjustments
which are based on the lessee’s
knowledge of decreases or increases
which will affect the allowance. Form
ONRR–4292 must be received by ONRR
within 3 months after the end of the
previous reporting period, unless ONRR
approves a longer period (during which
period the lessee shall continue to use
the allowance from the previous
reporting period).
(iv) For new wash plants, the lessee’s
initial form ONRR–4292 shall include
estimates of the allowable coal washing
costs for the applicable period. Cost
estimates shall be based upon the most
recently available operations data for
the plant, or if such data are not
available, the lessee shall use estimates
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based upon industry data for similar
coal wash plants.
(v) Washing allowances based on nonarm’s-length or no contract situations
which are in effect at the time these
regulations become effective will be
allowed to continue until such
allowances terminate. For the purposes
of this section, only those allowances
that have been approved by ONRR in
writing shall qualify as being in effect at
the time these regulations become
effective.
(vi) Upon request by ONRR, the lessee
shall submit all data used by the lessee
to prepare its forms ONRR–4292. The
data shall be provided within a
reasonable period of time, as
determined by ONRR.
(vii) ONRR may establish, in
appropriate circumstances, reporting
requirements which are different from
the requirements of this section.
(3) ONRR may establish coal washing
allowance reporting dates for individual
leases different from those specified in
this subpart in order to provide more
effective administration. Lessees will be
notified of any change in their reporting
period.
(4) Washing allowances must be
reported as a separate line on the form
ONRR–4430, unless ONRR approves a
different reporting procedure.
(d) Interest assessments for incorrect
or late reports and failure to report. (1)
If a lessee deducts a washing allowance
on its form ONRR–4430 without
complying with the requirements of this
section, the lessee shall be liable for
interest on the amount of such
deduction until the requirements of this
section are complied with. The lessee
also shall repay the amount of any
allowance which is disallowed by this
section.
(2) If a lessee erroneously reports a
washing allowance which results in an
underpayment of royalties, interest shall
be paid on the amount of that
underpayment.
(3) Interest required to be paid by this
section shall be determined in
accordance with § 1218.202 of this
chapter.
(e) Adjustments. (1) If the actual coal
washing allowance is less than the
amount the lessee has taken on form
ONRR–4430 for each month during the
allowance form reporting period, the
lessee shall be required to pay
additional royalties due plus interest
computed pursuant to § 1218.202,
retroactive to the first month the lessee
is authorized to deduct a washing
allowance. If the actual washing
allowance is greater than the amount the
lessee has estimated and taken during
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the reporting period, the lessee shall be
entitled to a credit, without interest.
(2) The lessee must submit a corrected
form ONRR–4430 to reflect actual costs,
together with any payment, in
accordance with instructions provided
by ONRR.
(f) Other washing cost determinations.
The provisions of this section shall
apply to determine washing costs when
establishing value using a net-back
valuation procedure or any other
procedure that requires deduction of
washing costs.
§ 1206.459
Allocation of washed coal.
(a) When coal is subjected to washing,
the washed coal must be allocated to the
leases from which it was extracted.
(b) When the net output of coal from
a washing plant is derived from coal
obtained from only one lease, the
quantity of washed coal allocable to the
lease will be based on the net output of
the washing plant.
(c) When the net output of coal from
a washing plant is derived from coal
obtained from more than one lease,
unless determined otherwise by BLM,
the quantity of net output of washed
coal allocable to each lease will be
based on the ratio of measured
quantities of coal delivered to the
washing plant and washed from each
lease compared to the total measured
quantities of coal delivered to the
washing plant and washed.
§ 1206.460
general.
Transportation allowances—
(a) For ad valorem leases subject to
§ 1206.456 of this subpart, where the
value for royalty purposes has been
determined at a point remote from the
lease or mine, ONRR shall, as
authorized by this section, allow a
deduction in determining value for
royalty purposes for the reasonable,
actual costs incurred to:
(1) Transport the coal from an Indian
lease to a sales point which is remote
from both the lease and mine; or
(2) 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. In-mine
transportation costs shall not be
included in the transportation
allowance.
(b) Under no circumstances will the
authorized washing allowance and the
transportation allowance reduce the
value for royalty purposes to zero.
(c)(1) When coal transported from a
mine to a wash plant is eligible for a
transportation allowance in accordance
with this section, the lessee is not
required to allocate transportation costs
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between the quantity of clean coal
output and the rejected waste material.
The transportation allowance shall be
authorized for the total production
which is transported. Transportation
allowances shall be expressed as a cost
per ton of cleaned coal transported.
(2) For coal that is not washed at a
wash plant, the transportation
allowance shall be authorized for the
total production which is transported.
Transportation allowances shall be
expressed as a cost per ton of coal
transported.
(3) Transportation costs shall only be
recognized as allowances when the
transported coal is sold and royalties are
reported and paid.
(d) If, after a review and/or audit,
ONRR determines that a lessee has
improperly determined a transportation
allowance authorized by this section,
then the lessee shall pay any additional
royalties, plus interest, determined in
accordance with § 1218.202 of this
chapter, or shall be entitled to a credit,
without interest.
(e) Lessees shall not
disproportionately allocate
transportation costs to Indian leases.
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§ 1206.461 Determination of
transportation allowances.
(a) Arm’s-length contracts. (1) For
transportation costs incurred by a lessee
pursuant to an arm’s-length contract, the
transportation allowance shall be the
reasonable, actual costs incurred by the
lessee for transporting the coal under
that contract, subject to monitoring,
review, audit, and possible future
adjustment. ONRR’s prior approval is
not required before a lessee may deduct
costs incurred under an arm’s-length
contract. However, before any deduction
may be taken, the lessee must submit a
completed page one of form ONRR–
4293, Coal Transportation Allowance
Report, in accordance with paragraph
(c)(1) of this section. A transportation
allowance may be claimed retroactively
for a period of not more than 3 months
prior to the first day of the month that
form ONRR–4293 is filed with ONRR,
unless ONRR approves a longer period
upon a showing of good cause by the
lessee.
(2) In conducting reviews and audits,
ONRR will examine whether the
contract reflects more than the
consideration actually transferred either
directly or indirectly from the lessee to
the transporter for the transportation. If
the contract reflects more than the total
consideration paid, then ONRR may
require that the transportation
allowance be determined in accordance
with paragraph (b) of this section.
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(3) If ONRR determines that the
consideration paid pursuant to an arm’slength transportation contract does not
reflect the reasonable value of the
transportation because of misconduct by
or between the contracting parties, or
because the lessee otherwise has
breached its duty to the lessor to market
the production for the mutual benefit of
the lessee and the lessor, then ONRR
shall require that the transportation
allowance be determined in accordance
with paragraph (b) of this section. When
ONRR determines that the value of the
transportation may be unreasonable,
ONRR will notify the lessee and give the
lessee an opportunity to provide written
information justifying the lessee’s
transportation costs.
(4) Where the lessee’s payments for
transportation under an arm’s-length
contract are not based on a dollar-perunit basis, the lessee shall convert
whatever consideration is paid to a
dollar value equivalent for the purposes
of this section.
(b) Non-arm’s-length or no contract.
(1) If a lessee has a non-arm’s-length
contract or has no contract, including
those situations where the lessee
performs transportation services for
itself, the transportation allowance will
be based upon the lessee’s reasonable
actual costs. All transportation
allowances deducted under a non-arm’slength or no contract situation are
subject to monitoring, review, audit, and
possible future adjustment. Prior ONRR
approval of transportation allowances is
not required for non-arm’s-length or no
contract situations. However, before any
estimated or actual deduction may be
taken, the lessee must submit a
completed form ONRR–4293 in
accordance with paragraph (c)(2) of this
section. A transportation allowance may
be claimed retroactively for a period of
not more than 3 months prior to the first
day of the month that form ONRR–4293
is filed with ONRR, unless ONRR
approves a longer period upon a
showing of good cause by the lessee.
ONRR will monitor the allowance
deductions to ensure that deductions
are reasonable and allowable. When
necessary or appropriate, ONRR may
direct a lessee to modify its estimated or
actual transportation allowance
deduction.
(2) The transportation allowance for
non-arm’s-length or no contract
situations shall be based upon the
lessee’s actual costs for transportation
during the reporting period, including
operating and maintenance expenses,
overhead, and either depreciation and a
return on undepreciated capital
investment in accordance with
paragraph (b)(2)(iv)(A) of this section, or
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36987
a cost equal to the depreciable
investment in the transportation system
multiplied by the rate of return in
accordance with paragraph (b)(2)(iv)(B)
of this section. Allowable capital costs
are generally those for depreciable fixed
assets (including costs of delivery and
installation of capital equipment) which
are an integral part of the transportation
system.
(i) Allowable operating expenses
include: Operations supervision and
engineering; operations labor; fuel;
utilities; materials; ad valorem property
taxes; rent; supplies; and any other
directly allocable and attributable
operating expense which the lessee can
document.
(ii) Allowable maintenance expenses
include: Maintenance of the
transportation system; maintenance of
equipment; maintenance labor; and
other directly allocable and attributable
maintenance expenses which the lessee
can document.
(iii) Overhead attributable and
allocable to the operation and
maintenance of the transportation
system is an allowable expense. State
and Federal income taxes and severance
taxes and other fees, including royalties,
are not allowable expenses.
(iv) A lessee may use either paragraph
(b)(2)(iv)(A) or (B) of this section. After
a lessee has elected to use either method
for a transportation system, the lessee
may not later elect to change to the
other alternative without approval of
ONRR.
(A) To compute depreciation, the
lessee may elect to use either a straightline depreciation method based on the
life of equipment or on the life of the
reserves which the transportation
system services, whichever is
appropriate, or a unit of production
method. After an election is made, the
lessee may not change methods without
ONRR approval. A change in ownership
of a transportation system shall not alter
the depreciation schedule established
by the original transporter/lessee for
purposes of the allowance calculation.
With or without a change in ownership,
a transportation system shall be
depreciated only once. Equipment shall
not be depreciated below a reasonable
salvage value.
(B) ONRR shall allow as a cost an
amount equal to the allowable capital
investment in the transportation system
multiplied by the rate of return
determined pursuant to paragraph
(b)(2)(B)(v) of this section. No allowance
shall be provided for depreciation. This
alternative shall apply only to
transportation facilities first placed in
service or acquired after March 1, 1989.
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Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations
(v) The rate of return shall be the
industrial rate associated with Standard
and Poor’s BBB rating. The rate of return
shall be the monthly average as
published in Standard and Poor’s Bond
Guide for the first month of the
reporting period of which the allowance
is applicable and shall be effective
during the reporting period. The rate
shall be redetermined at the beginning
of each subsequent transportation
allowance reporting period (which is
determined pursuant to paragraph (c)(2)
of this section).
(3) A lessee may apply to ONRR for
exception from the requirement that it
compute actual costs in accordance with
paragraphs (b)(1) and (2) of this section.
ONRR will grant the exception only if
the lessee has a rate for the
transportation approved by a Federal
agency for Indian leases. ONRR shall
deny the exception request if it
determines that the rate is excessive as
compared to arm’s-length transportation
charges by systems, owned by the lessee
or others, providing similar
transportation services in that area. If
there are no arm’s-length transportation
charges, ONRR shall deny the exception
request if:
(i) No Federal regulatory agency cost
analysis exists and the Federal
regulatory agency has declined to
investigate pursuant to ONRR timely
objections upon filing; and
(ii) The rate significantly exceeds the
lessee’s actual costs for transportation as
determined under this section.
(c) Reporting requirements—(1)
Arm’s-length contracts. (i) With the
exception of those transportation
allowances specified in paragraphs
(c)(1)(v) and (vi) of this section, the
lessee shall submit page one of the
initial form ONRR–4293 prior to, or at
the same time as, the transportation
allowance determined pursuant to an
arm’s-length contract is reported on
form ONRR–4430, Solid Minerals
Production and Royalty Report.
(ii) The initial form ONRR–4293 shall
be effective for a reporting period
beginning the month that the lessee is
first authorized to deduct a
transportation allowance and shall
continue until the end of the calendar
year, or until the applicable contract or
rate terminates or is modified or
amended, whichever is earlier.
(iii) After the initial reporting period
and for succeeding reporting periods,
lessees must submit page one of form
ONRR–4293 within 3 months after the
end of the calendar year, or after the
applicable contract or rate terminates or
is modified or amended, whichever is
earlier, unless ONRR approves a longer
period (during which period the lessee
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20:24 Aug 04, 2017
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shall continue to use the allowance from
the previous reporting period). Lessees
may request special reporting
procedures in unique allowance
reporting situations, such as those
related to spot sales.
(iv) ONRR may require that a lessee
submit arm’s-length transportation
contracts, production agreements,
operating agreements, and related
documents. Documents shall be
submitted within a reasonable time, as
determined by ONRR.
(v) Transportation allowances that are
based on arm’s-length contracts and
which are in effect at the time these
regulations become effective will be
allowed to continue until such
allowances terminate. For the purposes
of this section, only those allowances
that have been approved by ONRR in
writing shall qualify as being in effect at
the time these regulations become
effective.
(vi) ONRR may establish, in
appropriate circumstances, reporting
requirements that are different from the
requirements of this section.
(2) Non-arm’s-length or no contract.
(i) With the exception of those
transportation allowances specified in
paragraphs (c)(2)(v) and (vii) of this
section, the lessee shall submit an initial
form ONRR–4293 prior to, or at the
same time as, the transportation
allowance determined pursuant to a
non-arm’s-length contract or no contract
situation is reported on form ONRR–
4430, Solid Minerals Production and
Royalty Report. The initial report may
be based on estimated costs.
(ii) The initial form ONRR–4293 shall
be effective for a reporting period
beginning the month that the lessee first
is authorized to deduct a transportation
allowance and shall continue until the
end of the calendar year, or until the
transportation under the non-arm’slength contract or the no contract
situation terminates, whichever is
earlier.
(iii) For calendar-year reporting
periods succeeding the initial reporting
period, the lessee shall submit a
completed form ONRR–4293 containing
the actual costs for the previous
reporting period. If the transportation is
continuing, the lessee shall include on
form ONRR–4293 its estimated costs for
the next calendar year. The estimated
transportation allowance shall be based
on the actual costs for the previous
reporting period plus or minus any
adjustments that are based on the
lessee’s knowledge of decreases or
increases that will affect the allowance.
form ONRR–4293 must be received by
ONRR within 3 months after the end of
the previous reporting period, unless
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ONRR approves a longer period (during
which period the lessee shall continue
to use the allowance from the previous
reporting period).
(iv) For new transportation facilities
or arrangements, the lessee’s initial form
ONRR–4293 shall include estimates of
the allowable transportation costs for
the applicable period. Cost estimates
shall be based upon the most recently
available operations data for the
transportation system, or, if such data
are not available, the lessee shall use
estimates based upon industry data for
similar transportation systems.
(v) Non-arm’s-length contract or no
contract-based transportation
allowances that are in effect at the time
these regulations become effective will
be allowed to continue until such
allowances terminate. For purposes of
this section, only those allowances that
have been approved by ONRR in writing
shall qualify as being in effect at the
time these regulations become effective.
(vi) Upon request by ONRR, the lessee
shall submit all data used to prepare its
form ONRR–4293. The data shall be
provided within a reasonable period of
time, as determined by ONRR.
(vii) ONRR may establish, in
appropriate circumstances, reporting
requirements that are different from the
requirements of this section.
(viii) If the lessee is authorized to use
its Federal-agency-approved rate as its
transportation cost in accordance with
paragraph (b)(3) of this section, it shall
follow the reporting requirements of
paragraph (c)(1) of this section.
(3) ONRR may establish reporting
dates for individual lessees different
than those specified in this paragraph in
order to provide more effective
administration. Lessees will be notified
as to any change in their reporting
period.
(4) Transportation allowances must be
reported as a separate line item on form
ONRR–4430, unless ONRR approves a
different reporting procedure.
(d) Interest assessments for incorrect
or late reports and failure to report. (1)
If a lessee deducts a transportation
allowance on its form ONRR–4430
without complying with the
requirements of this section, the lessee
shall be liable for interest on the amount
of such deduction until the
requirements of this section are
complied with. The lessee also shall
repay the amount of any allowance
which is disallowed by this section.
(2) If a lessee erroneously reports a
transportation allowance which results
in an underpayment of royalties,
interest shall be paid on the amount of
that underpayment.
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(3) Interest required to be paid by this
section shall be determined in
accordance with § 1218.202 of this
chapter.
(e) Adjustments. (1) If the actual
transportation allowance is less than the
amount the lessee has taken on form
ONRR–4430 for each month during the
allowance form reporting period, the
lessee shall be required to pay
additional royalties due plus interest,
computed pursuant to § 1218.202 of this
chapter, retroactive to the first month
the lessee is authorized to deduct a
transportation allowance. If the actual
transportation allowance is greater than
the amount the lessee has estimated and
taken during the reporting period, the
lessee shall be entitled to a credit,
without interest.
(2) The lessee must submit a corrected
form ONRR–4430 to reflect actual costs,
together with any payment, in
accordance with instructions provided
by ONRR.
(f) Other transportation cost
determinations. The provisions of this
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20:24 Aug 04, 2017
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section shall apply to determine
transportation costs when establishing
value using a net-back valuation
procedure or any other procedure that
requires deduction of transportation
costs.
§ 1206.462
[Reserved]
§ 1206.463 In-situ and surface gasification
and liquefaction operations.
If an ad valorem Federal coal lease is
developed by in-situ or surface
gasification or liquefaction technology,
the lessee shall propose the value of
coal for royalty purposes to ONRR.
ONRR will review the lessee’s proposal
and issue a value determination. The
lessee may use its proposed value until
ONRR issues a value determination.
§ 1206.464 Value enhancement of
marketable coal.
If, prior to use, sale, or other
disposition, the lessee enhances the
value of coal after the coal has been
placed in marketable condition in
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36989
accordance with § 1206.456(h) of this
subpart, the lessee shall notify ONRR
that such processing is occurring or will
occur. The value of that production
shall be determined as follows:
(a) A value established for the
feedstock coal in marketable condition
by application of the provisions of
§ 1206.456(c)(2)(i) through (iv) of this
subpart; or,
(b) In the event that a value cannot be
established in accordance with
paragraph (a) of this section, then the
value of production will be determined
in accordance with § 1206.456(c)(2)(v)
of this subpart and the value shall be the
lessee’s gross proceeds accruing from
the disposition of the enhanced product,
reduced by ONRR-approved processing
costs and procedures including a rate of
return on investment equal to two times
the Standard and Poor’s BBB bond rate
applicable under § 1206.458(b)(2)(v) of
this subpart.
[FR Doc. 2017–16571 Filed 8–4–17; 8:45 am]
BILLING CODE 4335–30–P
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]]>Agencies
[Federal Register Volume 82, Number 150 (Monday, August 7, 2017)]
[Rules and Regulations]
[Pages 36934-36989]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2017-16571]
[[Page 36933]]
Vol. 82
Monday,
No. 150
August 7, 2017
Part III
Department of the Interior
-----------------------------------------------------------------------
Office of Natural Resources Revenue
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30 CFR Parts 1202 and 1206
Repeal of Consolidated Federal Oil & Gas and Federal & Indian Coal
Valuation Reform; Final Rule
Federal Register / Vol. 82 , No. 150 / Monday, August 7, 2017 / Rules
and Regulations
[[Page 36934]]
-----------------------------------------------------------------------
DEPARTMENT OF THE INTERIOR
Office of Natural Resources Revenue
30 CFR Parts 1202 and 1206
[Docket No. ONRR-2017-0001; DS63644000 DR2000000.CH7000 178D0102R2]
RIN 1012-AA20
Repeal of Consolidated Federal Oil & Gas and Federal & Indian
Coal Valuation Reform
AGENCY: Office of Natural Resources Revenue, Interior.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Office of Natural Resources Revenue (ONRR) is repealing
the Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation
Reform Final Rule, published July 1, 2016, and effective January 1,
2017. Simultaneously, ONRR is reinstating the valuation regulations
governing the valuation of Federal oil, Federal gas, and Federal and
Indian coal that were in effect before January 1, 2017.
DATES: This rule is effective on September 6, 2017.
FOR FURTHER INFORMATION CONTACT: For questions on technical issues,
contact Elizabeth Dawson at (303) 231-3653, Amy Lunt at (303) 231-3746,
Peter Christnacht at (303) 231-3651, or Karl Wunderlich at (303) 231-
3663.
SUPPLEMENTARY INFORMATION:
I. Background
A. General
This final rule repeals in its entirety the Consolidated Federal
Oil & Gas and Federal & Indian Coal Valuation Reform Final Rule (2017
Valuation Rule) that ONRR published in the Federal Register on July 1,
2016 (81 FR 43338), and that was effective on January 1, 2017. The 2017
Valuation Rule made changes to existing regulations governing royalty
valuation and reporting practices for oil, gas, and coal. As stated in
the 2017 Valuation Rule's preamble, the purpose of implementing the
rule was (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 revenue 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. 81 FR 43338.
After the 2017 Valuation Rule was published, however, ONRR
discovered several significant defects in the rule that would have
undermined its purpose and intent. In addition, during the same time
period (July 1, 2016, to the present) we received numerous comments
from the regulated community and other members of the public, both in
response to the proposed rule of repeal that we published in the
Federal Register on April 4, 2017, and in other public forums, that
were highly critical of certain provisions in the rule. In light of the
defects that we discovered in the rule and after carefully considering
all of the comments we received, we have decided to repeal the 2017
Valuation Rule in its entirety, principally for the following three
reasons:
First, the 2017 Valuation Rule has a number of defects that make
certain provisions challenging to comply with, implement, or enforce.
Absent their repeal, the rule would compromise ONRR's mission to
collect and account for mineral royalty revenues; could affect royalty
distributions to ONRR's State and Tribal partners; and would impose a
costly and unnecessary burden on Federal and Indian lessees.
Second, On March 28, 2017, the President issued E.O. 13783--
Promoting Energy Independence and Economic Growth, 82 FR 16093. The
executive order directs Federal agencies to review all existing
regulations and other agency actions and, ultimately, to suspend,
revise, or rescind any such regulations or actions that unnecessarily
burden the development of domestic energy resources beyond the degree
necessary to protect the public interest or otherwise comply with the
law. Based on our own internal review, as well as on the comments we
received both before and during the process of promulgating this rule
of repeal, we have concluded that certain provisions of the 2017
Valuation Rule would unnecessarily burden the development of Federal
oil and gas and Federal and Indian coal beyond the degree necessary to
protect the public interest or otherwise comply with the law.
Third, on March 29, 2017, the Secretary of the Interior (Secretary)
announced that he will reestablish the Royalty Policy Committee (RPC)
under the Federal Advisory Committee Act. The RPC will advise ONRR on
current and emerging issues related to the determination of fair market
value and the collection of royalties from energy and natural resources
on Federal and Indian lands. The RPC will be composed of Federal
representatives and stakeholders from energy and mineral interests,
academia, public interest groups, States, Indian Tribes, and individual
Indian mineral interest owners. The RPC will provide a forum for
engaging with key stakeholders and the public on many of the same
issues we attempted to address in the 2017 Valuation Rule. ONRR expects
that further internal assessment and analysis combined with
consultations facilitated by the RPC's reestablishment will lead to the
development and promulgation of a new, revised valuation rule that will
address the various problems that have now been identified in the rule
we are repealing.
At the same time that we are repealing the 2017 Valuation Rule, we
are reinstating the regulations governing the valuation of oil, natural
gas, and coal produced from Federal leases and coal produced from
Indian leases that were in effect before January 1, 2017. These
regulations will apply prospectively to oil, gas, and coal produced on
or after the effective date that we have specified in the DATES section
of this preamble. We intend to apply and construe the prior regulations
in a manner consistent with the preambles published in conjunction with
the original rulemakings and in accordance with administrative and
judicial decisions interpreting these regulations.
Finally, upon taking effect, this repeal of the 2017 Valuation Rule
will supersede the notification of the postponement of the
effectiveness of the rule that we published in the Federal Register on
February 27, 2017. 82 FR 11823. When this repeal takes effect, the so-
called administrative stay of the rule will be lifted.
B. Secretary's Authority To Promulgate Regulations or Reinstate Prior
Regulations Under FOGRMA
Section 301 of the Federal Oil and Gas Royalty Management Act
(FOGRMA), as amended, codified at 30 U.S.C. 1751, grants the Secretary
broad authority to prescribe such rules and regulations, issued in
conformity with the Administrative Procedure Act (APA), as he deems
reasonably necessary to create a thorough system for collecting and
accounting for Federal and Indian mineral royalties. FOGRMA creates the
legal framework for the collection and accounting system, but FOGRMA
also grants the Secretary, acting through ONRR, broad discretion as to
how to build it out. Put another way (as courts sometimes have), FOGRMA
grants the Secretary, acting through ONRR, broad discretion to regulate
interstitially to interpret and implement the statute.
There is not a single right way for ONRR to exercise its
congressionally
[[Page 36935]]
delegated authority to interpret and implement FOGRMA; on the contrary,
there are many ways in which ONRR may legitimately accomplish its task,
as long as the way it chooses is consistent with the statutory language
and the congressionally prescribed legal framework. ONRR believes that
the prior regulations, which will be reinstated by this final rule, are
fully consistent with FOGRMA and other applicable federal statutes and
are an effective and efficient means of valuing Federal and Indian
minerals, as evidenced by their long and successful use before the
promulgation of the 2017 Valuation Rule.
C. Chronology of Events Following Promulgation of 2017 Valuation Rule
On July 1, 2016, ONRR published the final 2017 Valuation Rule in
the Federal Register. Although the rule took effect on January 1, 2017,
first reports and royalty payments under it were not due until February
28, 2017.
To facilitate the transition to the new regulations, ONRR conducted
eleven training sessions for industry reporters in different locations
between October 17, 2016, and December 15, 2016. We designed the
training sessions to educate affected parties on how to value
production and report and pay royalties under the 2017 Valuation Rule.
The trainings also provided a forum in which lessees could ask us
questions about the rule and how ONRR would implement and enforce it.
At the same time that ONRR was conducting the trainings and reviewing
comments and questions about the rule, ONRR was also receiving numerous
written requests for guidance that asked many of the same questions
that were being raised at the live sessions.
The feedback we received through the training sessions and guidance
requests revealed certain unforeseen defects in, or unintended
consequences of, portions of the 2017 Valuation Rule. Lessees raised
multiple questions that ONRR had not previously considered and was not
prepared or able to answer, particularly with respect to the coal
valuation provisions. For example, lessees argued that valuing coal
based on the first arm's-length sale of coal as electricity is a
difficult task because the sale price of electricity does not reflect
the value of coal in a simple, predictable fashion--electricity markets
are too diverse and complex to trace electricity prices back to the
lease. Lessees also asked questions about how to value coal production
in certain non-arm's-length transactions under the new definition of
``coal cooperative.'' And lessees asked ONRR specific questions that we
had not previously considered about how, and under what circumstances,
we would implement the default provision with respect to oil, gas, and
coal. At bottom, by the middle of December 2016 we had become aware
that the rule contained several defects that, at a minimum, would
seriously complicate, and probably compromise, ONRR's ability to
implement and enforce certain provisions.
On December 29, 2016, three different sets of petitioners, some of
whom had previously requested guidance from ONRR, filed three separate
petitions challenging the 2017 Valuation Rule in the United States
District Court for the District of Wyoming. The petitioners alleged
that the rule created widespread uncertainty about reporting and
payment of royalties, and in some respects, was unreasonably difficult
to comply with. The petitioners' arguments echoed the questions and
concerns that had been raised at the reporter training sessions and in
various guidance requests.
By late January 2017 we recognized that implementing the 2017
Valuation Rule would be contrary to the rule's stated purpose of
offering greater simplicity, certainty, clarity, and consistency in
product valuation. We also recognized that the defects in the rule were
significant enough that implementation could undermine and compromise
ONRR's mission to collect, account for, and verify mineral royalties
for the United States and its State and Tribal partners.
With the February 28, 2017, reporting deadline approaching and
while we were actively considering internally what to do about the
previously identified defects in the 2017 Valuation Rule, the
petitioners in the litigation sent ONRR a letter (dated February 17,
2017) requesting that ONRR postpone the rule's effective date. Prompted
by that request, but based on ONRR's own independent assessment of the
defects in the rule and the harm that could result by requiring lessees
to comply with it, we decided that it was in the best interest of the
regulated community, the royalty beneficiaries, and the public in
general to preserve the regulatory status quo while the litigation was
pending. Accordingly, on February 27, 2017, we published in the Federal
Register a notification postponing the effectiveness of the rule
pursuant to 5 U.S.C. 705 of the APA, pending judicial review. 82 FR
11823.
Meanwhile, the nation had elected a new President in November 2016,
and the new administration had taken office on January 20, 2017. On
March 28, 2017, the President issued E.O. 13783--Promoting Energy
Independence and Economic Growth, 82 FR 16093, which directed the heads
of executive agencies to review all existing regulations, orders,
guidance documents, policies, and other similar agency actions that
potentially burden the development or use of domestically produced
energy resources and, ultimately, to suspend, revise, or rescind those
agency actions that do so unnecessarily. The executive order provided
additional impetus to our ongoing review of the 2017 Valuation Rule,
and we discovered some additional substantive problems with the rule.
As a result of all of those developments, on April 4, 2017, we
published in the Federal Register a notice proposing to repeal the 2017
Valuation Rule in its entirety and soliciting public comment on the
proposal. 82 FR 16323. At the same time, we recognized that certain
provisions in the 2017 Valuation Rule had been, and continued to be,
well received. Therefore, concurrent with the proposed repeal, we also
published an Advance Notice of Proposed Rulemaking soliciting public
comment on two scenarios: (1) If the 2017 Valuation Rule were repealed,
whether a new valuation rule is needed and, if so, what particular
issues the new valuation rule should address; and (2) if the 2017
Valuation Rule were not repealed, what changes should be made to the
rule (82 FR 16325, April 4, 2017).
The comment period for the proposed repeal rule closed on May 4,
2017. We received more than a thousand comments from 2,342 commenters
both for and against repeal. We carefully considered all of the
comments we received and, for the reasons discussed further below, have
decided at this time to repeal the 2017 Valuation Rule in its entirety.
ONRR will continue to assess the substantive issues addressed in the
2017 Valuation Rule and expects to in the near future promulgate a new,
revised valuation rule that will address the various problems that have
been identified in the rule we are repealing.
D. Substantive Defects in, and Administrative Challenges Posed by, the
2017 Valuation Rule
1. Valuing Coal Using the Sale Price of Electricity
The 2017 Valuation Rule required lessees to value certain non-
arm's-length sales of Federal and Indian coal based on the first arm's-
length sale of electricity. For several reasons we have concluded that
this provision of the rule is unnecessarily complicated and burdensome
to implement or enforce.
[[Page 36936]]
ONRR has long valued oil, gas, and coal based on the first arm's-
length sale of the resource because we believe that such sales are the
best indicator of market value. In promulgating the 2017 Valuation
Rule, ONRR incorrectly assumed that it would be reasonable for lessees
to ``net back'' to the value of coal from arm's-length electrical
sales, the same way that lessees ``net back'' to value from the first
arm's-length sale by an affiliate. We also incorrectly assumed that
using such sales would accurately reflect the value of coal because the
majority of coal mined from Federal and Indian lands is used to
generate electricity. But we failed to fully consider other factors
that determine what a generating company charges for its electricity.
The price of electricity also reflects the company's costs to
construct, operate, and maintain its depreciable capital assets; its
costs to operate and maintain other necessary infrastructure; its costs
to comply with applicable Federal and State laws; and its corporate
overhead and other internal corporate costs. All of those factors may
(and do) vary from company to company and from state to state. Unlike
an arm's-length sale of coal, where the sale price directly and
accurately reflects the value of the coal, the sale price of
electricity is determined by many factors in addition to the price of
coal.
Moreover, electricity is generated, transmitted, and distributed
through regional grids where the electricity is maintained for delivery
at specified voltages and frequencies. The regional grids function as
pools that are fed by electricity generated from a variety of different
resources, including natural gas, solar, wind, geothermal, and coal.
The electricity is then sold in wholesale markets in a variety of ways,
including, but not limited to, firm and non-firm sales, long-term and
short-term sales, interruptible sales, and daily spot-market sales. The
markets also include ancillary services, such as spinning and non-
spinning reserves, voltage and frequency control, and load following.
Each of these sales commands a different price. We have concluded at
this time that the approach taken in the 2017 Valuation Rule
establishes an unreasonable requirement for the lessee or ONRR to
dissect these services and sales, and trace those sales back to coal
produced from the lease, particularly because electricity generated
from coal is pooled with electricity generated from other resources
before it is sold. In short, it would be very challenging for lessees
to calculate and pay royalties based on the sale price of electricity
and similarly challenging for ONRR to verify the accuracy of those
calculations.
Finally, the 2017 Valuation Rule failed to address the increasingly
common situation in which gross proceeds accrue to a lessee's
affiliate. The rule stated that lessees value their Federal and Indian
coal production on ``the gross proceeds accruing to you for the power
plant's arm's-length sales of the electricity less applicable
transportation and washing deductions.'' (Emphasis added.) As used in
that regulation, the word ``you'' referred to the lessee, which the
rule defined as ``any person to whom the United States, an Indian
Tribe, and/or individual mineral owner issues a lease, and any person
who has been assigned all or part of record title, operating rights, or
an obligation to make royalty or other payments by the lease.'' For
Federal and Indian coal, the definition of lessee included ``an
operator, payor, or other person with no lease interest who makes
royalty payments on the lessee's behalf.'' The rule was silent,
however, on how to value coal when the gross proceeds accrued to a
lessee's affiliate. This oversight would have undermined ONRR's mission
and responsibility to collect and verify royalties, which would have
had a direct impact on revenue accruing to ONRR's State and Tribal
partners.
2. Definition of ``Coal Cooperative''
The 2017 Valuation Rule defined ``coal cooperatives'' to capture
the arm's-length value of coal in those limited circumstances in which
unaffiliated companies cooperate to market and exchange coal for mutual
economic advantage. But the term was defective in several respects. At
bottom, the definition was overly broad and ambiguous and created too
much confusion to be effective or enforceable. And because the
definition was too broad, it asked lessees to perform an unreasonably
difficult task, that is, to value coal based on the sale price received
by a third-party company that was neither affiliated, nor in a
contractual relationship, with the lessee.
More specifically, the 2017 Valuation Rule did not define what
entities are included in a coal cooperative, nor did the rule
adequately identify what type of behavior, conduct, or economic
relationships constitute a coal cooperative. Thus, the rule did not
provide lessees with meaningful direction to enable them to determine
whether they are part of a coal cooperative and, if so, what other
entities may also be part of that cooperative. Indeed, the definition
was so broad that it would have captured almost any entity engaged in
the production, marketing, and transportation of coal, regardless of
how far removed that entity was from the lessee. Consequently, it would
have been unreasonable for either ONRR or the lessee to determine where
the coal cooperative began and where it ended. By extension, it would
have been unreasonable for either ONRR or the lessee to determine when
the first arm's-length sale occurred. As a result, lessees could not
have valued their coal, and ONRR (or States or Tribes, acting under
authority by ONRR) could not have verified that value. That inadvertent
and unfortunate confusion was, of course, directly contrary to ONRR's
intent when it promulgated the rule.
What is more, the definition would have required lessees to perform
an unreasonably difficult task. For example, a federal lessee in a coal
cooperative could sell its coal to an unaffiliated third party that is
also in the cooperative. But because the parties are part of the same
cooperative, we would not have considered that sale to be an arm's-
length transaction. The third party then could have transferred the
coal to an affiliate, who could have sold the coal at arm's-length.
Under those circumstances, the rule would have required the lessee to
value its coal based on the sales price received by the third-party's
affiliate, a company that was neither affiliated, nor in a contractual
relationship, with the lessee. Under this scenario, the lessee probably
could not have obtained the sales price information it needed to
determine the royalty-bearing value of its coal.
Last, the definition of coal cooperative was unnecessary because it
attempted to solve a problem that was already addressed by the prior
(and soon-to-be-reinstated) regulations. In the example, under the
prior regulations ONRR would still obtain fair market value for the
coal because the lessee and third party lack opposing economic
interests, and we therefore would apply the provision in the
regulations for valuing coal in non-arm's-length transactions. Under
that provision, depending on the circumstances, ONRR could still value
the coal based on the first arm's-length transaction under the fourth
benchmark in 30 CFR 1206.257(c)(2) (Federal coal) or 1206.456(c)(2)
(Indian coal).
3. Default Provision
Statutes and lease terms grant the Secretary considerable authority
and discretion to establish the reasonable value of Federal and Indian
minerals. By promulgating the so-called default provision, ONRR was
attempting to offer greater clarity, consistency, and
[[Page 36937]]
predictability by defining when, where, and how the Secretary would
exercise his discretionary authority to use an alternative methodology
to value minerals. We attempted to explain that we would invoke the
default provision only in specific and limited situations when we could
not determine whether a lessee had properly paid royalties under the
regulations. Those situations include when a lessee fails to provide
documents during an audit, when a lessee engages in misconduct, when a
lessee breaches its duty to market, or any other situation that
compromises our ability to reasonably determine the fair market value
of the oil, gas, or coal. But because we described those circumstances
so broadly, without limits or meaningful guidance, the rule created
more confusion and uncertainty than it resolved.
We also failed to appreciate the numerous administrative challenges
posed by the default provision. For example, the 2017 Valuation Rule
did not identify who within ONRR has the authority to invoke the
default provision or whether that decision must be approved or may be
appealed. The rule defined ``misconduct'' so broadly that lessees,
ONRR, and ONRR's State and Tribal partners were left without any
meaningful guidance on what type of misconduct triggered the default
provision. At the same time, the rule was silent on whether ONRR must
make a formal finding of misconduct before the default provision is
invoked, who has the authority make such a finding, and whether such a
finding is subject to review. We believe that those ambiguities would
have led to very inconsistent applications of the rule.
The 2017 Valuation Rule also did not address whether the default
provision was a tool of last resort or a vehicle to collect and verify
royalties more efficiently. For example, the rule offered no guidance
on what would happen if ONRR invoked the default provision to value
production because the lessee failed to provide documents necessary to
value the production, and the lessee later produces those documents.
Nor did the rule fully explain how the default provision interacted
with ONRR's civil penalty regulations. For example, if a lessee
knowingly or willfully fails to provide documents during an audit, the
rule was silent on whether ONRR would issue a civil penalty for failing
to permit an audit, or whether ONRR would complete the audit by valuing
the production under the default provision, or both. These challenges,
and many others, made the default provision confusing to lessees and
would have made it difficult, for ONRR to implement and enforce.
Finally, with or without the default provision, ONRR already has
the authority to establish the value of Federal and Indian minerals
when we cannot determine whether a lessee properly paid royalties.
While the default provision was a well-intended attempt to provide
certainty and predictability by clarifying and codifying that
authority, we now recognize that the default provision created more
confusion, uncertainty, and apprehension than it resolved.
4. Requirement That Arm's-Length Contracts Be in Writing and Signed by
All Parties
The 2017 Valuation Rule required both lessees and their affiliates
to reduce all contracts, contract revisions, or amendments to writing
and have them signed by all of the parties. The rule further stated
that where the lessee did not have in place a written contract signed
by all of the parties, ONRR could use the default provision to value
the oil, gas, or coal at issue.
Based on the comments we received, we have reconsidered our
position on this requirement. We now agree with the majority of
commenters that this provision of the rule is unnecessary, overly
burdensome, and potentially defective. First, this provision overlooked
the fact that unwritten agreements or unsigned, written agreements may
be binding, legally enforceable contracts. Second, this provision
contradicted the definition of ``contract'' in the rule itself, which
defined ``contract'' as ``any oral or written agreement . . . that is
enforceable by law'' and which did not require the contract to be
signed by the parties. Third, the preamble stated that ONRR could
discount or ignore an arm's-length contact if the contract were not in
writing and signed by all of the parties, which ran counter to ONRR's
long-held position that arm's-length sales are the best indicator of
market value. Fourth, the rule required the lessees' affiliates to have
all of their contracts, contract revisions, and amendments reduced to
writing and signed by all of the parties, despite the fact that the
affiliates are not Federal or Indian lessees and the rule was not
purporting to regulate them. And fifth, the rule burdened lessees and
their affiliates with an unnecessary and potentially costly obligation
to conform contracts to meet ONRR's specifications, which could
increase the cost of production and delay the delivery of mineral
resources.
5. Valuation Guidance and Determinations
The 2017 Valuation Rule required Federal oil and gas and Indian
coal lessees to request valuation determinations from ONRR that,
because of an oversight in the rule, we would no longer have the
regulatory authority to issue. The prior regulations authorized ONRR to
issue a binding valuation determination in response to a request from
an oil, gas, or coal lessee. The 2017 Valuation Rule, however,
inadvertently stripped ONRR of that authority or, at the very least,
was unclear as to whether ONRR could continue to exercise that
authority.
More specifically, sections 1206.108 (Federal oil), 1206.148
(Federal gas), 1206.258 (Federal coal), and 1206.458 (Indian coal) all
provided that a lessee could request a valuation determination from
ONRR. The rule then provided that ONRR could do one of three things in
response to the request: (1) Request that the Assistant Secretary for
Policy Management and Budget issue a determination; (2) decide that
ONRR will issue non-binding guidance; or (3) notify the lessee that
ONRR will not provide a determination or guidance. The rule was silent,
however, on whether ONRR could issue a valuation determination in
response to a request. Thus, under the 2017 Valuation Rule ONRR
arguably had no authority to continue to issue valuation
determinations.
This was particularly problematic because several sections in the
2017 Valuation Rule required lessees to request valuation
determinations from ONRR, and several other provisions required ONRR to
issue such determinations. Those references appear in the following
sections:
------------------------------------------------------------------------
Federal gas Federal oil Federal coal Indian coal
------------------------------------------------------------------------
1206.141(e) 1206.111(d) 1206.252(b)(2) 1206.452(b)(2)
1206.142(f) ................. 1206.261(c) 1206.461(c)
1206.153(d) ................. 1206.268(c) 1206.468(c)
1206.160(b)(2) ................. ................ ................
[[Page 36938]]
1206.160(c) ................. ................ ................
------------------------------------------------------------------------
At bottom, this oversight means that lessees cannot comply with the
2017 Valuation Rule and ONRR cannot enforce it, which undermines the
purpose and intent of the rule. Even if ONRR could issue valuation
determinations in the absence of a regulation, these sections fail to
specify whether ONRR's determinations are binding on ONRR or the
lessee, and if so, whether the lessee may appeal the determination.
Other provisions of the regulations cross-reference the terms
``valuation determinations'' and ``determinations'' without defining
those terms or stating whether those terms are synonymous or distinct.
In addition, section 1206.458, which applies to Indian coal,
incorrectly provides that the Assistant Secretary for Policy,
Management and Budget will issue a valuation determination regarding
Indian coal. But only the Assistant Secretary for Indian Affairs has
the authority to issue a valuation determination for questions
concerning Indian lands. All in all, the numerous defects and the lack
of consistency in the regulations governing valuation determinations
undermined the purpose and intent of the rule and would have created
confusion and inefficiencies and imposed additional burdens on both
ONRR and the regulated community.
6. Flared Gas Valuation
Under the 2017 Valuation Rule, lessees who are required to pay
royalty on flared gas would have been required to value the vented and
flared gas using an index price for the area if one is available. If an
index price were not available, then the lessee would have been
required to propose a method to ONRR under the default provision. In
those circumstances, we expected that the proposed method would value
the vented and flared gas based on the arm's-length sale price the
lessee received for other gas sold from the same lease. ONRR now
recognizes that this regulation would have imposed an unnecessary and
potentially costly administrative burden on certain lessees. It would
also have run counter to ONRR's belief and position that arm's-length
transactions are the best indicator of value.
For example, there is no viable index price in North Dakota. Thus,
lessees in North Dakota would have been required to propose a method to
ONRR under the default provision. For lessees that also sell gas
produced from the same lease at arm's-length, we assumed that the
lessee would propose to value its vented and flared gas on the price it
received in the arm's-length sale. Thus, those lessees would have
reported one volume, on one line, pursuant to a single valuation
method.
Lessees in the San Juan Basin in New Mexico, however, would have
been held to a different standard. Because there is a viable index
price in the San Juan Basin, lessees there would be required to value
their gas using the index price. That is true even if the lessee were
selling the same gas from the same lease at arm's length to third-party
buyers. Under those circumstances, the lessee would be required to
report two separate volumes, on two separate lines, using two separate
valuation methods. This inconsistency, and the additional
administrative burden it would impose on certain lessees, was not our
intent when we promulgated the rule.
In sum, the 2017 Valuation Rule would have imposed an unnecessary
and potentially costly administrative burden on certain lessees. At the
same time, the rule would run counter to ONRR's long-held belief and
position that prices under arm's-length contracts are the best measure
of value.
7. Changes in Administration and Energy Policy
The nation elected a new President in November 2016, and the new
administration took office on January 20, 2017. Through various public
announcements the new administration quickly signaled that it would
adopt and follow a national energy policy different than that of its
predecessor, one that emphasized and prioritized the reduction of
Federal regulatory burdens on industry. On March 28, 2017, President
Donald J. Trump issued E.O. 13783--Promoting Energy Independence and
Economic Growth (Executive Order) (82 FR 16093, Mar. 31, 2017). The
Executive Order begins by stating broadly that ``[i]t is in the
national interest to promote clean and safe development of our Nation's
vast energy resources, while at the same time avoiding regulatory
burdens that unnecessarily encumber energy production, constrain
economic growth, and prevent job creation.'' The Executive Order then
continues, ``Accordingly, it is the policy of the United States that
executive departments and agencies (agencies) immediately review
existing regulations that potentially burden the development or use of
domestically produced energy resources and appropriately suspend,
revise, or rescind those that unduly burden the development of domestic
energy resources beyond the degree necessary to protect the public
interest or otherwise comply with the law.'' To that end, the Executive
Order directs the heads of all agencies to ``review all existing
regulations, orders, guidance documents, policies, and any other
similar agency actions (collectively, agency actions) that potentially
burden the development or use of domestically produced energy
resources, with particular attention to oil, natural gas, coal, and
nuclear energy resources.'' The Executive Order defines ``burden'' to
mean ``to unnecessarily obstruct, delay, curtail, or otherwise impose
significant costs on the siting, permitting, production, utilization,
transmission, or delivery of energy resources.''
Pursuant to the Executive Order, ONRR included the 2017 Valuation
Rule in its review of regulations that potentially burden the
development or use of domestically produced energy resources. As a
result of that review, we concluded that the rule, as a whole, would
unduly burden or unnecessarily obstruct, delay, curtail, or otherwise
impose significant costs on the production, utilization, or delivery of
Federal oil or gas or Federal or Indian coal. For example, because we
realized that valuing coal based on the arm's-length sale of
electricity is a very challenging task, we concluded that Federal and
Indian coal lessees would incur unnecessary and unwarranted costs in
trying to comply with those provisions in the 2017 Valuation Rule.
Likewise, because we had realized that the definition of ``coal
cooperative'' in the rule was too broad and ambiguous to comply with or
enforce, we concluded that lessees in cooperatives would incur
unnecessary and unwarranted costs in an effort to determine the
royalty-bearing value of their coal. These defects alone would have
resulted in significant costs that would have served as a financial
disincentive to producing coal from Federal or Indian lands.
In sum, a number of provisions of the 2017 Valuation Rule would
have unnecessarily obstructed, delayed,
[[Page 36939]]
curtailed, or otherwise imposed significant costs on the production,
utilization, or delivery of Federal oil and gas and Federal and Indian
coal. The repeal of the 2017 Valuation Rule therefore is consistent
with the policy announced in the Executive Order and the direction that
the Executive Order provides to executive agencies. The Department
takes seriously its responsibility to ensure that taxpayers receive the
full value from Federal mineral leases, which is why ONRR intends to
continue to consider future changes and develop a new rulemaking after
further analysis and consultations with our key stakeholders and the
general public.
II. Comments on Proposed Rules
On April 4, 2017, ONRR published a Notice of Proposed Rulemaking
(NPRM) to invite public comment on the possible repeal of the 2017
Valuation Rule. 82 FR 16323. During the 30-day public comment period,
we received more than one thousand pages of written comments from over
2,342 commenters. We received comments from industry, industry trade
groups, Members of Congress, State governors and agencies, local
municipalities, Tribes, local businesses, public interest groups, and
individual commenters. The majority of comments--both those opposing
and those supporting repeal--addressed the Federal and Indian coal
valuation provisions in the 2017 Valuation Rule.
Comments opposing repeal of the 2017 Valuation Rule generally
argued that repealing the 2017 Valuation Rule would result in
undervaluing our nation's oil, gas, and coal resources; would result in
a waste of government resources; and would violate certain provisions
in the APA.
Comments supporting repeal of the 2017 Valuation Rule generally
faulted the following elements of the rule: (a) The method that lessees
must use to calculate value on coal sold under non-arm's-length
contracts; (b) ONRR's definition of ``contract'' and ``misconduct'';
(c) the default provision; (d) changes to transportation and processing
allowances; (e) the option to value Federal gas sold under non-arm's-
length transactions based on index prices; and (f) percentage-of-
proceeds contracts.
A. General Comments
Public Comment: Many commenters who work in the coal industry or
live in coal-mining-dependent communities, including a tribe,
maintained that the 2017 Valuation Rule went too far. They argued that
the 2017 Valuation Rule imposed unwarranted valuation methods, which,
they contended, hinder transparency and create complex and subjective
oil, gas, and coal valuations. They claimed that the 2017 Valuation
Rule would cause economic harm to the oil, gas, and coal industries,
including the loss of jobs.
ONRR also received a few comments advocating that oil, gas, and
coal production should stop and that the minerals should ``stay in the
ground.''
ONRR Response: We agree that the 2017 Valuation Rule's process for
using the sale price of electricity to value coal would be too complex
to comply with, implement, or enforce. We also agree that other aspects
of the 2017 Valuation Rule, including the default provision and the
definition of coal cooperative, are too broad to be implemented
effectively, which could make reporting and paying royalties more
burdensome and less predictable and transparent.
Although we appreciate the comments regarding keeping fossil fuels
in the ground and the socioeconomic impact of the 2017 Valuation Rule
on communities that rely on coal production, both issues are beyond the
scope of this rulemaking.
Public Comment: An industry trade group commented that complexities
in the 2017 Valuation Rule would make it difficult for small businesses
to comply. The commenter also claimed that smaller companies would not
be able to take deductions, resulting in a higher royalty rate.
ONRR Response: For the reasons stated previously, we agree that
implementing the rule would increase the costs of compliance and
unnecessarily burden the production of Federal and Indian mineral
resources. We also agree that those increased compliance costs could
disproportionately impact smaller companies that have fewer resources
to comply.
Public Comment: We received comments from two States asserting that
repealing the rule would unfairly reduce the royalties that the States
receive under the 2017 Valuation Rule. Conversely, we received a
comment from another State asserting that not repealing the rule would
result in decreased production that would adversely affect its royalty
share.
ONRR Response: Based on our economic analysis, we recognize that
repealing the 2017 Valuation Rule will result in a decrease in
royalties (between 0.8 percent and 1.0 percent) to our State partners
compared to what they would receive if ONRR implemented and enforced
the rule. ONRR will continue to assess options for updating our
valuation regulations and expects to, in the near future, propose new
rules that could offset, in whole or in part, the decrease in royalties
shared with State partners in future years compared to what would
otherwise result from the repeal of the 2017 Valuation Rule. As
discussed previously, the rule has a number of defects that make
certain provisions challenging to comply with, implement, or enforce.
ONRR's attempt to implement or enforce the rule as written would have
compromised our ability to collect and account for mineral royalty
revenues, which in turn may have affected distributions to other
royalty beneficiaries. It would also have imposed an additional
financial and administrative burden on our State and Tribal partners,
who audit and verify royalty payments.
We also agree with the State commenter that implementing the 2017
Valuation Rule could result in some decreased production, particularly
for coal, because the burden of complying with certain provisions of
the rule would serve as a disincentive to production. This too would
result in decreased royalty distributions to our State and Tribal
partners. All told, we believe that the modest economic gains that
might result from implementing the rule are far outweighed by the
potentially significant burden on industry, ONRR, and our State and
Tribal partners from implementing and enforcing a rule with significant
defects.
Public Comment: Industry trade groups claimed that the 2017
Valuation Rule was unnecessarily complex, which would increase the
costs of complying with the regulation. The groups maintained that the
complexity and costs would discourage industry from entering into
Federal or Indian leases.
ONRR Response: ONRR agrees that several unforeseen defects in the
2017 Valuation Rule have the potential to significantly increase the
cost and administrative burden of compliance, which could create a
disincentive to entering into, and producing oil, gas, and coal from,
Federal or Indian leases.
Public Comment: We received comments encouraging collaboration with
our stakeholders in any future rulemaking. Many industry commenters
encouraged working through the RPC to advise ONRR on valuation
policies.
ONRR Response: As discussed previously, the Secretary has recently
re-established the RPC to collaborate with our stakeholders in any
future rulemaking. The RPC will provide a forum for engaging with the
public on many of the same issues we attempted to address in the 2017
Valuation Rule.
[[Page 36940]]
We look forward to working with our stakeholders in the RPC on a future
rulemaking.
B. Fair Return to Government
Public Comment: Many commenters and comments disagreed about the
need either to revise or to repeal the 2017 Valuation Rule. Some public
interest groups and some members of the public asserted that ONRR's
regulations have undervalued royalties for many years and that the
changes made in the rule would ensure that royalties are based on fair
market value. Industry trade groups and other members of the public
maintained that the rule would result in values that inflate the value
of the resources.
ONRR Response: We disagree that repealing the rule will prevent the
government from receiving a fair market value for its mineral
resources. The prior (and soon-to-be-reinstated) regulations have been
in place for more than twenty years and serve as a reasonable,
reliable, and consistent method for valuing Federal and Indian minerals
for royalty purposes. This is evidenced by the fact that when we
promulgated and published the final 2017 Valuation Rule, we estimated
that it would generate less than 1 percent in additional royalties. 81
FR 43359. Moreover, as we discussed in proposing the 2017 Valuation
Rule, we were attempting to make ``proactive and innovative changes''
to the rules ``to increase the effectiveness and efficiency of the
rules.'' We believe today, as we always have, that the prior (and soon-
to-be-reinstated) regulations provide a fair market return for Federal
and Indian minerals. That said, we will continue to look for
opportunities to improve our regulations, including opportunities to
improve the return to taxpayers and Indian mineral owners and to
streamline processes for both ONRR and industry.
Public Comment: A public interest group maintained that our
regulations should use a market value based on the value of the
resource where it is ultimately consumed. The comment asserted that
ONRR does not collect royalties at the market and that we should more
aggressively pursue a value at the market instead of a value at the
lease.
ONRR Response: While we appreciate the comment, whether ONRR should
use a market value based on the value of the resource where it is
ultimately consumed is outside the scope of this rulemaking.
C. Administrative Procedure Act (APA)
One member of Congress, two State officials, and several public
interest groups asserted that ONRR failed to comply with certain
requirements in the APA.
Public Comment: Some commenters stated that ONRR's decision to
postpone the effectiveness of the 2017 Valuation Rule indicates ONRR's
intent to repeal the rule, without regard to any comments received in a
rulemaking process, in violation of APA rulemaking requirements.
ONRR Response: The 2017 Valuation Rule was effective on January 1,
2017. On February 27, 2017, for the reasons discussed in the preamble
to this rule, including the filing of three separate petitions
challenging the rule in the United States District Court for the
District of Wyoming, ONRR postponed the effectiveness of the rule,
pending judicial review. 82 FR 11823. ONRR did not decide to repeal the
2017 Valuation Rule, however, until after we had reviewed and
considered of all comments that we received in response to the proposed
rule of repeal, which we published in the Federal Register on April 4,
2017. 82 FR 16323.
Public Comment: We also received comments contending that ONRR did
not provide a reasoned basis to repeal the rule.
ONRR Response: We are providing a reasoned basis to repeal the rule
in the preamble to this rule. Before we proposed to repeal the 2017
Valuation Rule, we identified several defective provisions in the rule
that would have made these provisions unnecessarily complicated and
burdensome to comply with, implement, or enforce. When we published the
proposed rule of repeal on April 4, 2017, we identified some of those
defects and specifically invited public comment on them as well as on
other aspects of the 2017 Valuation Rule.
Public Comment: Public interest groups and some individuals claimed
that the 30-day comment period in the NPRM is unreasonable and violates
the APA. The commenters asserted that ONRR went to great effort to
promulgate the 2017 Valuation Rule and was now proposing to repeal it
with only a 30-day comment period.
ONRR Response: Under the APA's rulemaking procedures, agencies must
publish a notice of proposed rulemaking in the Federal Register; allow
interested persons an opportunity to comment on the proposed rule; and,
after considering those comments, publish the final rule. The APA
requires an opportunity to submit ``written data, views, or
arguments,'' yet there is no required minimum comment period under the
APA. See 5 U.S.C. 553(c). Through this rulemaking we are complying with
the requirements set forth in the APA. We provided a reasonable amount
of time to allow interested parties a sufficient opportunity to
consider the repeal and its supporting analysis and to provide
meaningful comments.
Public Comment: One commenter asserted that ONRR must analyze the
record compiled to issue the rule and provide a reasoned explanation
for the repeal. According to the commenter, ONRR has not cited any new
scientific or technical information in support of repeal.
ONRR Response: The comment is not clear on whether it refers to the
record for the 2017 Valuation Rule or the record for the repeal of the
2017 Valuation Rule. Regardless, we provided the purpose and
justification for both rules and responded to comments that we received
during both rulemakings. Specifically, we analyzed the record compiled
during the 2017 Valuation Rule rulemaking. 81 FR 43338. In the preamble
and responses to comments for this final rule, ONRR also analyzed the
record compiled for the proposed repeal. We have determined to repeal
the 2017 Valuation Rule for the reasons stated herein.
D. Government Efficiency
Public Comment: One member of Congress and a public interest group
asserted that repealing the rule amounts to wasting government
resources because ONRR is abandoning the work that it performed while
promulgating the 2017 Valuation Rule. These commenters also argued that
if there are problems with the rule, ONRR should address those problems
separately and not necessarily abandon the rule in its entirety.
ONRR Response: We disagree that repealing the rule is a waste of
government resources. As noted previously, the 2017 Valuation Rule has
several defects that make certain provisions unnecessarily complicated
and burdensome to comply with, implement, or enforce. We have concluded
that those defects are significant enough that implementing the rule
would compromise our mission to collect and account for mineral royalty
revenues for Federal oil and gas and Federal and Indian coal. The cost
of implementing the rule and subsequently trying to fix the defects in
one or more separate rulemakings would far exceed the cost of repealing
and replacing the rule.
[[Page 36941]]
We also disagree that ONRR is abandoning the work that it
previously performed. As noted previously, the Secretary is
reestablishing the RPC to increase stakeholder engagement on many of
the same issues the 2017 Valuation Rule attempted to address. We hope
and expect that this new round of public engagement will lead to the
development of a new valuation rule. The work that ONRR performed while
promulgating the 2017 Valuation Rule, as well as the stakeholder
comments during that rulemaking, will no doubt serve as valuable
resources for the RPC as it fulfills its charge to advise ONRR on
current and emerging issues related to the determination of fair market
value and the collection of royalties from resources on Federal and
Indian lands.
E. Federal and Indian Coal Valuation
For coal not sold under arm's-length contracts, the 2017 Valuation
Rule removed the ability for lessees to use the benchmarks found in the
prior (and soon-to-be-reinstated) regulations. Instead, under the 2017
Valuation Rule lessees had to value their coal on the first arm's-
length sale of the coal. In cases where that first arm's-length sale
was for the sale of electricity, lessees had to use the prices that
they received for electricity to ``net back'' to the value of the coal
at the lease.
1. Valuing Coal Based on Benchmarks
Public Comment: ONRR received numerous comments from industry,
government officials, industry trade groups, public interest groups,
and the general public regarding how lessees should value Federal and
Indian coal not sold at arm's length.
Some commenters maintained that the prior rule's non-arm's-length
valuation benchmarks fail to capture the true value of coal that
lessees sell in non-arm's-length transactions. The commenters posited
that the benchmarks do not allow ONRR to determine royalty value based
on a coal lessee's affiliate's subsequent arm's-length sale, including
overseas sales, resulting in the coal industries taking advantage of a
``loophole.'' These commenters maintained that the most effective
method to determine the value of Federal and Indian coal not sold under
arm's-length contracts is to use the first arm's-length sale of coal
sold by the lessee's affiliate.
ONRR also received comments from industry, government officials,
industry trade groups, and the general public that supported repealing
the rule because they found the old benchmarks to be time-tested and
robust. These commenters maintained that the 2017 Valuation Rule's
method to determine value for royalty purposes when Federal and Indian
lessees do not sell their coal at arm's-length was difficult to
implement and did not establish an appropriate value, for royalty
purposes, of Federal or Indian coal at the mine. One commenter asserted
that the rule amounted to an unlawful royalty on the value of services
that an affiliate provides to the lessee.
ONRR Response: We believe that arm's-length transactions generally
are the best indicators of market value because they provide a
consistent and accurate measure of value. But we do not agree that the
benchmarks in the prior (and soon-to-be-reinstated) regulations create
a ``loophole'' that permits coal lessees to shirk their royalty
obligations. Indeed, ONRR has used the benchmarks to order additional
royalties due based on an affiliate's arm's-length sale, including in
those circumstances in which the coal is sold by the affiliate in the
international market. While we recognize that the benchmarks are
sometimes difficult to apply, we also recognize that benchmarks are a
proven and time-tested method for determining the fair value of Federal
and Indian coal that the lessee does not sell at arm's-length.
2. Valuing Coal Based on ``Net Back'' From Electric Sales
Public Comment: Numerous coal companies and a coal industry trade
group expressed a range of concerns about using electric sales to value
coal sold in non-arm's-length situations without competing economic
interests. In particular, these commenters highlighted extraordinary
complexities in electric markets and the electric producers' resource
portfolios. They objected to valuing coal by way of electricity, which
the commenters asserted is a separate commodity subject to its own
unique market factors and forces and regulatory requirements, and
argued that geothermal regulations were inappropriate as a means for
determining transmission and production allowances. Overall, industry
commenters argued that the 2017 Valuation Rule's effort to value coal
through arm's-length sales of electricity was overly burdensome if not
functionally impossible. A number of comments from the general public
also asserted that valuing coal as electricity would make electricity
more expensive because the increased royalty burden would be passed on
to the consumer.
ONRR Response: ONRR has carefully considered these comments and, as
discussed in the preamble to this rule, has concluded and agrees that
the 2017 Valuation Rule's process for ``netting back'' to the value of
coal from arm's-length electrical sales is an unnecessarily complicated
and burdensome task to perform and does not necessarily result in an
accurate valuation of the coal.
3. Other Issues Related to Valuing Coal
Public Comment: Two companies, one State government representative,
three industry trade groups, and one member of the public supporting
the repeal observed that the 2017 Valuation Rule handles coal lessees
differently than oil and gas lessees and claimed that this treatment is
discriminatory. They pointed out that, like coal, gas can be used to
generate electricity, but that, unlike coal, ONRR does not require
Federal or Indian gas lessees to value their gas production based on
electricity sales ``netted back'' to the lease.
ONRR Response: We did not intend to discriminate against coal by
valuing the coal based on electricity sales. Coal, oil, and gas are all
different commodities, subject to different market factors and forces
and regulatory requirements. In our experience, the first arm's-length
sale of much Federal or Indian coal is as electricity. That is rarely
the case for Federal or Indian oil and gas.
Public Comment: One company suggested that the costs to comply with
the 2017 Valuation Rule's non arm's-length coal valuation provisions
would offset any increase in royalty that ONRR would receive. The
company further claimed that ONRR's own analysis shows that the
royalties received from these provisions would be minimal if not
negative.
ONRR Response: We agree that the 2017 Valuation Rule's requirement
to value coal based on electric sales is overly burdensome and would
result in substantial compliance costs.
F. Definitions
1. Misconduct
The 2017 Valuation Rule included a new definition of ``misconduct''
to use in conjunction with the default provision.
Public Comment: One member of the public took issue with the 2017
Valuation Rule's definition of the term ``misconduct.'' The commenter
maintained that the term has derogatory implications that could affect
a lessee's reputation. The commenter noted that the definition added
tension between ONRR and the industry that it regulates.
ONRR Response: We defined ``misconduct'' to clarify when ONRR would
use its discretion to determine the value of production under the
[[Page 36942]]
default provision. We now believe the definition is too ambiguous
because it provides almost no guidance as to what type of conduct
qualifies as misconduct. At the same time, the rule is silent on
whether ONRR must make a formal finding of misconduct before the
default provision is invoked, who has the authority make such a
finding, and whether such a finding is reviewable on appeal. Taken
together, these ambiguities could lead to inconsistent applications of
the rule, which would undermine the purpose and intent of the rule.
While we cannot surmise how a finding of misconduct would impact a
lessee's reputation, we do agree with the commenter that the ambiguity
of the definition perpetuated (and perhaps aggravated) the tension and
apprehension that we were attempting to rectify.
2. Coal Cooperative
The 2017 Valuation Rule added a new definition of the term ``coal
cooperative'' that included 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 company asserted that, by determining in
advance that transactions between coal cooperatives are non-arm's-
length, ONRR failed to take into account its longstanding criteria for
determining whether entities are affiliated. The commenter further
contended that ONRR has not provided any evidence to support that coal
cooperatives are engaging in non-arm's-length transactions. The company
concludes that this is arbitrary, capricious, and contrary to law.
ONRR Response: For the reasons discussed in the preamble to this
rule, we agree that the definition of coal cooperatives in the 2017
Valuation Rule is overly broad and ambiguous and would create too much
confusion to be effective or enforceable. We also agree that the
definition is unnecessary because ONRR can evaluate such transactions
on a case-by-case basis under the prior (and soon-to-be-reinstated)
regulations.
G. Default Provision
The 2017 Valuation Rule included the so-called default provision,
which allowed ONRR great discretion to value a lessee's oil, gas, and
coal production in circumstances in which we could not determine
whether a lessee properly paid royalties under the regulations. We
explained that such circumstances included, but were 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 using other measures of value.
Public Comment: Companies and industry trade groups overwhelmingly
opposed the default provision. Many general public commenters also
opposed it. The commenters asserted that the default provision gave
ONRR ``overly broad'' discretion to determine the value of production.
An oil and gas industry trade group asserted that the default provision
allowed ONRR to ``second guess'' lessees' reporting and payment in
subsequent years, potentially causing lessees to incur late payment
interest and penalties. A State official raised concerns that the
default provision could have a chilling effect on coal production from
Federal and Indian lands.
Public interest groups and other members of the general public
approved of the default provision, at least in principle. These
commenters asserted that eliminating the default provision would hinder
ONRR's ability to ensure a fair value of Federal and Indian mineral
resources, specifically for coal. One public interest group stated that
the default provision simply codified the Secretary's authority to
determine royalty value and clarified when and how ONRR anticipated
using that authority.
ONRR Response: The comments alone demonstrate how the default
provision created far more confusion, uncertainty, and apprehension
than we intended or anticipated. Under FOGRMA, as amended, the
Secretary indisputably has the authority and discretion to determine
the reasonable value of Federal and Indian minerals. By promulgating
the default provision, we attempted to offer greater clarity,
consistency, and predictability by defining when, where, and how ONRR
would value production in those circumstances in which we could not
determine whether a lessee properly paid royalties under the
regulations. We drafted the rule broadly to encompass every scenario in
which ONRR would be forced to invoke the default provision. We realize
now that in doing so, we provided little in the way of meaningful
guidance on how and when ONRR would invoke its authority. Moreover,
because the rule was so broad, it created the perception that ONRR
would look past the valuation regulations and value production under
the default provision regardless of whether the lessee properly
reported and paid royalties under our regulations. This widespread
confusion defeated the very purpose and intent of including a default
provision in the rule.
Also, we disagree with those commenters who claimed that
eliminating the default provision would hinder ONRR's ability to ensure
a fair value of Federal and Indian mineral resources. Indeed, with or
without the default provision, ONRR has the authority to establish the
value of Federal and Indian minerals when we cannot determine whether a
lessee properly paid royalties under the regulations. ONRR exercised
this authority under our prior regulations, and we will continue to
exercise that authority now that those regulations will be reinstated.
Typically we use this authority in limited circumstances to establish a
reasonable value of production using market-based transaction data,
which has always been the basis for our royalty valuation rules.
Therefore, the repeal of the default provision will have the same small
and speculative royalty impact as its implementation.
H. Allowances
In the 2017 Valuation Rule ONRR eliminated the regulation allowing
us to approve transportation allowances in excess of 50 percent of the
value of a lessee's oil production. The rule also eliminated lessees'
ability to net transportation costs in their gross proceeds
calculations (``transportation factors''). The 2017 Valuation Rule also
eliminated both our ability to grant extraordinary processing
allowances and to approve requests for lessees to exceed the 66\2/3\
percent limitation on processing allowances.
Public Comment: Coal companies and coal industry trade groups
asserted that coal transportation allowances were poorly defined. They
also objected to the 2017 Valuation Rule's requirement that they use
the geothermal allowance regulations to ``net back'' to the value of
coal where the first arm's-length sale is electricity. Oil and gas
industry unanimously opposed the rule's cap on transportation and
processing allowances of 50 percent and 66\2/3\ percent, respectively.
Public interest groups generally opposed repealing the allowance
provisions in the 2017 Valuation Rule. Some commenters suggested that
allowance caps create more transparency and are easier to enforce. One
public interest group advocated for eliminating all allowances,
suggesting that they are a form of subsidy. Another public interest
group reiterated its view
[[Page 36943]]
that coal transportation and washing allowances should, like oil and
gas, be limited to 50 percent and 66\2/3\ percent, respectively. A
member of the general public asserted that ONRR should give standard
deductions for transportation and coal washing to reduce administrative
burden and to ensure a fair return to taxpayers.
ONRR Response: We appreciate the variety of responses, but whether
ONRR should eliminate all transportation allowances or establish a
standard allowance are questions that are outside the scope of this
rulemaking. The United States shares in certain expenses that occur
downstream or away from the lease, including costs associated with
transportation, gas processing, and coal washing, because the United
States benefits from lessees selling their production at a market
instead of at the lease.
We agree that, in practice, the requirement that coal lessees use
the geothermal allowance regulations to ``net back'' to the value of
coal where the first arm's-length sale is electricity is unnecessarily
complicated and burdensome. While we disagree that the provisions in
the 2017 Valuation Rule that would have capped oil and gas
transportation allowances were arbitrary and capricious, we recognize
that each cap would impose additional costs on some operators.
Public Comment: ONRR received comments from industry trade groups
stating that the 2017 Valuation Rule arbitrarily reversed a
longstanding deep-water-gathering policy that permitted lessees to take
transportation allowances for moving oil and gas production on the OCS.
In contrast, a public interest group asserted the deep-water-
gathering policy allowed improper deductions under ONRR's regulatory
scheme prior to the 2017 Valuation Rule. The commenter maintained that
repealing the 2017 Valuation Rule removes language that ensures
appropriate deep-water transportation allowances.
ONRR Response: By repealing the 2017 Valuation Rule and reinstating
the prior regulations, ONRR's longstanding deep-water-gathering policy
will remain in effect, and ONRR will continue to implement it to the
extent that it is consistent with the prior regulations. Nonetheless,
ONRR believes that the deep-water-gathering policy is a matter that is
appropriate to revisit and reconsider. ONRR will be further considering
this matter, including through consultations as part of the RPC
process.
I. Index-Based Gas Valuation Option
The 2017 Valuation Rule added an index-price valuation method that
lessees who do not sell their gas under an arm's-length sale could have
elected to use in lieu of valuing their gas on their first arm's-length
sale. ONRR based the method on publicly-available index prices, less a
specified deduction to account for processing and transportation costs.
Public Comment: An industry trade group and a member of the public
cited the shortcomings in the index-based gas valuation option as one
reason for repealing the 2017 Valuation Rule. While they supported the
use of index-based valuation in concept, they argued that the index-
based valuation option in the rule is unreasonable and, at times,
arbitrary for the following reasons: (1) ONRR did not provide the
option to arm's-length lessees; (2) the index option could result in a
price so high that it would disincentivize lessees from using it; (3)
the adjustments for transportation and processing were too low; and (4)
ONRR did not provide any standards for when and why it might change the
adjustments.
ONRR Response: We agree with the commenters that this is an area
requiring further analysis. Given the mutual interest in exploring
index-based valuation options, we believe the newly re-commissioned RPC
will provide a valuable forum to engage our stakeholders in a
meaningful way on this topic.
J. Percentage of Proceeds Contracts
Lessees sometimes sell their gas under arm's-length length
percentage-of-proceeds (POP) contracts for a price that is based on a
specific percentage of the proceeds that the purchaser receives after
processing the gas. The 2017 Valuation Rule required lessees with POP
contracts to report and pay royalties as processed gas. This rule of
repeal allows lessees to report and value POP contract sales as
unprocessed gas.
Public Comment: An industry trade group maintained that lessees
would find it difficult to value gas sold under arm's-length POP
contracts because they lack access to information from the midstream
processors and/or purchasers.
ONRR Response: Our experience is that the value lessees receive
under a POP contract is usually net of certain costs incurred to place
the gas into marketable condition. The 2017 Valuation Rule did not
change the lessee's obligation to ensure that it is not deducting costs
to place gas in marketable condition at no cost to the Federal
government; repealing the rule likewise does not change that
obligation. Nonetheless, we believe that how to value gas sold under
arm's-length POP contracts is an appropriate topic for the RPC, and we
look forward to engaging with members of the public and industry
stakeholders to explore different options for reporting POP contracts.
K. Requirement of Written, Signed Contracts
Although the 2017 Valuation Rule defined ``contract'' to include
legally enforceable oral agreements, the rule itself required a lessee
or its affiliate to have all of its contracts, contract revisions or
amendments in writing and signed by all of the parties. If the lessee
did not have a written contract, signed by all of the parties, then
ONRR could use the default provision to determine value.
Public Comment: Several commenters disagreed with the 2017
Valuation Rule's requirement that all contracts for the sale,
transportation, processing, or washing of oil, gas, or coal be in
writing and signed by all parties to the contract. These commenters
maintained that such a restriction ignores that unwritten and unsigned
contracts are legally enforceable.
ONRR Response: We adopted the requirement that all contracts be in
writing and signed by all parties to enhance our ability to verify the
accuracy of royalty reports and payments. For the reasons stated in the
preamble to this rule, we reconsidered our position and now agree that
this provision is unnecessary, overly burdensome, and potentially
defective. The prior (and soon-to-be-reinstated) regulations do not
require all contracts to be in writing and signed by all parties. But,
under 30 CFR 1207.5, we will continue to require lessees to place in
written form and maintain copies of all sales contracts and to maintain
copies of other contracts and agreements for accounting or auditing
purposes.
III. Procedural Matters
A. Summary Cost and Royalty Impact Data
The economic impact analysis that we prepared in the 2017 Valuation
Rule used 2010 royalty data. These economic impacts reflected market
conditions--commodity price, volumes, etc.--that existed in 2010. In
evaluating the economic impacts of repealing the rule, we used more
recent royalty data. Using data from 2015 versus 2010 provides an
estimate that is more in line with current market projections of future
[[Page 36944]]
commodity prices. The market for these resources changed between 2010
and 2015, with the value of the resources generally decreasing. Not
surprisingly, our updated analysis shows a somewhat smaller decrease in
royalty payments compared to the analysis that accompanies the 2017
Valuation Rule. Overall, our estimates for the previous rule, using
2010 data, projected costs to industry of $74.78 million per year (with
roughly corresponding benefits to the Treasury and States); this rule,
using 2015 data, the projected costs to industry from the 2017
Valuation Rule total $67.4 million per year; thus repeal of the rule
results in $67.4 million in benefits to industry (with roughly
corresponding benefits to the Treasury and States).
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. This repeal has cost impacts
that will result in decreased royalty collections. The net impact of
these provisions is an estimated annual decrease in royalty collections
of between $60.1 million and $74.8 million. This represents between 0.8
percent and 1.0 percent of the total Federal oil, gas, and coal
royalties that we collected in 2015. Although the 2017 Valuation Rule
was stayed before the first reporting and payments were due, some
lessees had already implemented changes in their related systems and
reporting procedures. Therefore, some lessees may incur additional
costs from implementing this rule because some lessees may have to undo
the system changes that they put in place in anticipation of first
reporting under the 2017 Valuation Rule on February 28, 2017. We are
unable to quantify that cost at this time.
Unless otherwise indicated, the numbers in the following tables are
rounded to three significant digits.
1. Industry
The table below lists ONRR's itemized low, mid-range, and high
estimates of the costs and benefits that industry would incur in the
first year. Industry would receive these benefits in the same amount
each year thereafter.
Summary of Royalty Impacts to Industry
----------------------------------------------------------------------------------------------------------------
Rule provision Low Mid High
----------------------------------------------------------------------------------------------------------------
Gas--restore benchmarks:
Remove affiliate resale..................................... $0 $1,360,000 $2,710,000
Remove index................................................ 10,600,000 10,600,000 10,600,000
NGLs--restore benchmarks:
Remove affiliate resale..................................... 0 754,000 1,510,000
Remove index................................................ (2,210,000) (2,210,000) (2,210,000)
Gas transportation 50 percent limitation exceptions reinstated.. 87,000 87,000 87,000
Processing allowance 66\2/3\ percent limitation exceptions 42,700 42,700 42,700
reinstated.....................................................
POP contracts processing allowance exceptions of 66\2/3\ percent 9,470,000 9,470,000 9,470,000
reinstated.....................................................
Extraordinary processing allowance reinstated................... 14,200,000 14,200,000 14,200,000
Deep-water-gathering reinstated................................. 23,900,000 28,100,000 32,300,000
Oil transportation 50 percent limitation exceptions reinstated.. 0 0 0
Oil and gas line losses allowance reinstated.................... 3,140,000 3,140,000 3,140,000
BBB bond rate change removed.................................... 5,740,000 5,740,000 5,740,000
Coal--non-arm's-length netback reinstated....................... (1,030,000) 0 1,030,000
Removing index option administrative costs...................... (303,000) (303,000) (303,000)
Removing deep-water-gathering administrative costs.............. (3,560,000) (3,560,000) (3,560,000)
-----------------------------------------------
Total....................................................... 60,100,000 67,400,000 74,800,000
----------------------------------------------------------------------------------------------------------------
Note: totals from this table and others in this analysis may not add due to rounding.
Benefit--Reinstatement of the Valuation Benchmarks for Non-Arm's-Length
Dispositions of Federal Unprocessed Gas, Residue Gas, and Coalbed
Methane
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, and 39, respectively) for calendar year 2015. We
did not include 2016 in any of our data sets because lessees are still
adjusting their reports for that year and the reported data is still
going through ONRR's edits.
We then extracted gas royalty data for non-arm's-length
transactions reported with the sales type code NARM. We also extracted
gas royalty data for sales type code POOL because royalty reporters may
also use this code to report certain non-arm's-length transactions.
Based on our experience with auditing transactions that use sales type
code POOL, only a relatively small portion of transactions are non-
arm's-length. Therefore, we used 10 percent of the POOL volumes in our
economic analysis of the volumes of gas sold at non-arm's length.
Based on our experience auditing production sold under non-arm's-
length contracts, we find that industry would incur a royalty decrease
between $0.00 and $0.05 per MMBtu under our proposal to use the
benchmarks instead of the affiliate's first arm's-length resale to
value gas production for royalty purposes. We address the royalty
impact of the index-based option below.
We generated a range of potential royalty decreases by assuming no
change in royalties for the low estimate, $0.025 per MMBtu for the mid-
range estimate, and $0.05 per MMBtu for the high estimate. We then
multiplied the NARM volume and 10 percent of the POOL volume reported
to ONRR in 2015 by the potential royalty decrease.
The results below are an estimated benefit to industry due to an
annual royalty decrease of between zero and approximately $5.4 million.
We reduced this estimate by one-half and assumed the mid-point of
$0.025 totaling $1.36 million. This assumes that 50 percent of the
lessees selling production under non-arm's-length arrangements would
have chosen this option under the 2017 Valuation Rule.
[[Page 36945]]
----------------------------------------------------------------------------------------------------------------
Royalty decrease ($)
2015 MMBtu volume -----------------------------------------------
(non-rounded) Low ($0.00) Mid ($0.025) High ($0.05)
----------------------------------------------------------------------------------------------------------------
NARM volume.................................. 97,869,053 $0 $2,446,726 $4,893,453
10% POOL volume.............................. 10,614,876 0 265,372 530,744
------------------------------------------------------------------
Total.................................... 108,483,929 0 2,712,098 5,424,196
------------------------------------------------------------------
50% of lessees choose this option............ ................. 0 1,360,000 2,710,000
----------------------------------------------------------------------------------------------------------------
Benefit--Termination of the Index-Based Option To Value Non-Arm's-
Length Sales of Federal Unprocessed Gas, Residue Gas, and Coalbed
Methane
To estimate the royalty impact of removing 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 seven major
geographic areas with active index prices: The Green River Basin, San
Juan Basin, Piceance and Uinta Basins, Powder River Basin, Wind River
Basin, Permian Basin, and Offshore Gulf of Mexico (GOM). These areas
account for approximately 95 percent of all Federal gas produced. To
calculate the estimated impact, we performed the following steps:
First, 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. Second, we subtracted the transportation deduction that we
specified in the 2017 Valuation Rule from the highest index price that
we identified in the first step. Third, we 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 the second
step. Fourth, we then multiplied the royalty volume by the monthly
difference that we calculated in the third step to calculate a monthly
royalty difference for each region. And fifth, we totaled the
difference that we calculated in the fourth step for the regions.
In 2015, the estimated royalties due using the index-based option
was greater than the reported royalties in every month during our
analysis.
We estimate the benefit to industry due to this change to be a
decrease in royalty payments of approximately $10.6 million annually.
This estimate represents an average decrease of approximately 9.8
percent, or $0.026 per MMBtu, based on an annual royalty volume of
154,104,793 MMBtu (for NARM and 10 percent POOL reported sales type
codes). This would have been the first time that we offered this
option; therefore, we did not know how many payors would choose it. We
reduced this estimate by one-half, assuming that 50 percent of lessees
with non-arm's-length sales would have chosen this option.
----------------------------------------------------------------------------------------------------------------
GOM gas Other gas Total
----------------------------------------------------------------------------------------------------------------
2015 royalties.................................................. $72,216,537 $143,618,273 $215,834,810
Royalty under index option...................................... 79,359,207 157,684,860 237,044,067
Difference...................................................... 7,142,670 14,066,587 21,209,257
Per unit change ($/MMBtu)....................................... 0.030 0.025 0.026
% Change........................................................ 9.9% 9.8% 9.8%
50% of lessees choose this option............................... .............. .............. 10,600,000
----------------------------------------------------------------------------------------------------------------
Benefit--Reinstatement of the Valuation Benchmarks for Non-Arm's-Length
Dispositions of Federal NGLs
Like the valuation changes that we discussed previously, for
Federal unprocessed, residue, and coalbed methane gas valuation, this
rule will value processed Federal NGLs under the prior valuation
benchmarks rather than either (1) tracing the first arm's-length sale
or (2) using the index-based option discussed previously. Lessees will
no longer have the option to value royalties using an index price value
derived from an NGL commercial price bulletin less a theoretical
processing allowance that included theoretical transportation and
fractionation of the NGLs. We again used the 2015 NARM and POOL NGL
data that lessees reported to ONRR for this analysis.
We performed the same analysis for valuation using the first arm's-
length sale for Federal unprocessed, residue, and coalbed methane gas,
as we discussed. 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 decrease. Based on
our experience, we estimate that the NGL resale margin, similar to gas,
would range from zero to $0.03 per gallon. Thus, our estimated royalty
decrease is zero for the low, $0.015 per gallon for the mid-range, and
$0.03 per gallon for the high range. The results below show a mid-range
decrease of $754,000 in royalty obligations using these assumptions,
and, again, we reduced them by one-half under the assumption that 50
percent of lessees would have chosen this option.
----------------------------------------------------------------------------------------------------------------
2015 gallons Royalty decrease ($)
(rounded to -----------------------------------------------
the nearest Low ($0.00
gallon) cents) Mid ($0.15) High ($0.03)
----------------------------------------------------------------------------------------------------------------
NARM volume..................................... 66,911,096 $0 $1,003,666 $2,007,333
[[Page 36946]]
10% of POOL volume.............................. 33,675,717 0 505,136 1,010,272
---------------------------------------------------------------
Total....................................... 100,586,813 0 1,508,802 3,017,604
----------------------------------------------------------------------------------------------------------------
50% of lessees choose this option............... .............. 0 754,000 1,510,000
----------------------------------------------------------------------------------------------------------------
Cost--Termination of the Index-Based Option To Value Non-Arm's-Length
Dispositions of Federal NGLs
Like the Federal unprocessed, residue, and coalbed methane gas
changes that we discussed, lessees will no longer have the option to
pay royalties on Federal NGLs production using an index-based value,
less a theoretical processing allowance that includes transportation
and fractionation. We used the same 2015 NARM and POOL transaction data
for NGLs for this analysis. We were unable to compare NGL prices
reported on the form ONRR-2014 to those in commercial price bulletins
because the prices that lessees report on the form ONRR-2014 are a
single rolled-up price for all NGLs and the bulletins price each NGL
product (such as ethane and propane) separately. Therefore, we
calculated a weighted price, or basket price, from the published prices
based on typical NGL product volumes, as well as based our analysis on
the royalty changes that result from removal of the theoretical
processing allowance provided under this option.
----------------------------------------------------------------------------------------------------------------
GOM NGLs Other NGLs Total
----------------------------------------------------------------------------------------------------------------
2015 royalties.................................................. $22,292,763 $9,884,982 $32,177,746
Royalty under index option...................................... $20,165,669 $7,585,605 $27,751,273
Difference...................................................... ($2,127,095) ($2,299,378) ($4,426,472)
Per-unit change ($/gal)......................................... ($0.004) ($0.008) ($0.006)
Percent change.................................................. -9.5% -23.3% -13.8%
50% of lessees choose this option............................... .............. .............. ($2,210,000)
----------------------------------------------------------------------------------------------------------------
Cost--Termination of the Index-Based Option To Value Non-Arm's-Length
Federal Unprocessed Gas, Residue Gas, Coalbed Methane, and NGLs
ONRR expects that industry will incur additional administrative
costs from losing the option to use the index-based option to value
non-arm's-length dispositions of Federal unprocessed gas, residue gas,
coalbed methane, and NGLs. Lessees will have to calculate the value of
their production using the valuation benchmarks, increasing the time
that it takes to calculate the correct price. Lessees will also have to
calculate their specific transportation rate for gas, and processing
allowance for NGLs, rather than using the ONRR-specified theoretical
values.
For the 50 percent of lessees that we estimated would use this
option, we estimate that eliminating the index-based option will
increase 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. In 2015, ONRR received approximately
16 percent more lines than from the data used in the prior rule. We
used tables from the Bureau of Labor Statistics (BLS) (https://www.bls.gov/oes/current/oes132011.htm#nat), which we updated to use
current BLS data 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 $53.42 per hour = $38.16 [mean hourly wage] x 1.4
[benefits cost factor]. Using a labor cost factor of $53.42 per hour,
we estimate that the annual administrative cost to industry will be
approximately $303,000.
----------------------------------------------------------------------------------------------------------------
Estimated
Time burden per lines reported Annual burden
line reported using index hours
(min) option (50%)
----------------------------------------------------------------------------------------------------------------
Electronic reporting (99%)................................... 1.5 221,780 5,544
Manual reporting (1%)........................................ 3.5 2,240 131
Industry labor cost/hour..................................... ................. .............. $53.42
--------------------------------------------------
Total cost to industry................................... ................. .............. $303,000
----------------------------------------------------------------------------------------------------------------
Benefit--Allow Transportation Allowances in Excess of 50 Percent of the
Value of Federal Gas
Prior to the 2017 Valuation Rule, the 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. The 2017 Valuation Rule eliminated the lessees'
ability to exceed that limit. This rule reinstates the lessees' ability
to request and receive approval to exceed the 50 percent limitation. To
estimate the impacts associated with this change, we first identified
all calendar year 2015 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
benefit to industry of $87,000.
[[Page 36947]]
Benefit--Allow Transportation Allowances in Excess of 50 Percent of the
Value of Federal Oil
Prior to the 2017 Valuation Rule, the Federal oil valuation
regulations limited lessees' transportation allowances to 50 percent of
the value of the oil unless they requested and received approval to
exceed that limit. The 2017 Valuation Rule eliminated the lessees'
ability to exceed that limit. This rule reinstates the lessees' ability
to request and receive approval to exceed the 50-percent limitation. To
estimate the costs associated with this change, we searched for
calendar year 2015-reported oil transportation allowance rates that
exceeded the 50-percent limit. We did not find any lines for oil
transportation that exceeded the 50 percent, so there will be no impact
to industry. But companies may exceed the 50-percent limit in the
future.
Benefit--Allow Processing Allowances in Excess of 66\2/3\ Percent of
the Value of the NGLs for Federal Gas
Prior to the 2017 Valuation Rule, the Federal gas valuation
regulations limited lessees' processing allowances to 66\2/3\ percent
of the value of the NGLs unless they requested and received approval to
exceed that limit. The 2017 Valuation Rule eliminated lessees' ability
to exceed that limit. This rule reinstates the lessees' ability to
request and receive approval to exceed the 66\2/3\-percent limitation.
To estimate the cost to industry associated with this change, we first
identified all calendar year 2015-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
benefit to industry of $42,700.
Benefit--Arm's-Length POP Contracts Not Subject to the 66\2/3\ Percent
Processing Allowance Limit for Federal Gas
In this rule and the rule in effect prior to the 2017 Valuation
Rule, lessees with POP contracts paid royalties based on their gross
proceeds as long as they paid a minimum value equal to 100 percent of
the value of the residue gas. Under the 2017 Valuation Rule, we do not
allow lessees with POP contracts to deduct more than the 66\2/3\
percent of the value of the NGLs. This rule reinstates the previous
regulation's provision allowing lessees with POP contracts to pay
royalties based on their gross proceeds, as long as those gross
proceeds are, at a minimum, equal to 100 percent of the value of the
residue gas. 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 could not, when combined,
exceed an equivalent value of 100 percent of the NGLs' value. By
repealing the 2017 Valuation Rule, the combined value of each product
that the lessee gives up to the processing plant could, again,
potentially exceed two-thirds of the NGLs' value.
Lessees report POP contracts to ONRR using sales type codes APOP
for arm's-length POP contracts and NPOP for non-arm's-length POP
contracts. Because lessees report arm's-length POP contract sales as
unprocessed gas, there are no reported processing allowances for us to
analyze, and we cannot determine the breakout between residue gas and
NGLs. Lessees do report residue gas and NGLs separately for non-arm's-
length POP contracts. However, these reported volumes constitute only
0.07 percent of all the natural gas royalty volumes reported to ONRR.
We deemed the non-arm's-length POP volume to be too low to adequately
assess the impact of this provision on both arm's-length POP and non-
arm's-length POP contracts.
Therefore, we examined all reported calendar year 2015 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 NGL
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 2015 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 many POP contracts. We
calculated 30 percent of both the value of residue gas and the NGLs to
approximate a theoretical 30-percent processing deduction. We then
compared the 30-percent total of residue gas and NGLs values to 66\2/3\
percent of the NGLs value (the maximum allowance under the 2017
Valuation Rule). The table below summarizes these calculations, which
we rounded to the nearest dollar:
----------------------------------------------------------------------------------------------------------------
2015 royalty
value prior to 70% 30%
allowances
----------------------------------------------------------------------------------------------------------------
Residue gas..................................... $494,401,673 $346,081,171 $148,320,502
NGLs............................................ 132,618,537 92,832,976 39,785,561
---------------------------------------------------------------
Total....................................... 627,020,209 438,914,147 188,106,063
---------------------------------------------------------------
66.67% limit.................................... 88,412,358 (132,618,537 x \2/3\)
Difference...................................... 99,693,705 ($188,106,063 - $88,412,357)
----------------------------------------------------------------------------------------------------------------
Our analysis shows that the theoretical processing deduction for 30
percent of the value of residue gas and NGLs ($188 million) under our
assumed onshore POP contract allowance would exceed the 66\2/3\ cap
($88 million) under this rule.
In our analysis for the 2017 Valuation Rule, the theoretical
deduction did not exceed the allowance cap, and we estimated that this
change would result in no impact. The 2015 data, however, did show that
the theoretical deduction exceeded the allowance cap, and there will be
an economic impact by repealing the 2017 Valuation Rule. This is
primarily due to the changing price relationship between gas and NGLs.
We estimated that the benefit to industry would be $9.47 million by
taking the royalty value that exceeds the POP contract allowance ($100
million) and dividing by the total of non-POP volume (1,582,143,530
MMBtu) to calculate a per-MMBtu rate of $0.06. We then applied the
$0.06 rate to the POP contract total volume of 157,764,948 MMBtu to get
the estimated increase of $9.47 million. For the sake of this analysis,
we assumed that all processing costs incurred were allowable.
[[Page 36948]]
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
2015 MMBtu volume............................................... 1,582,143,530
Rate/MMBtu over limit........................................... $0.06 ($99,693,705/1,582,143,530)
POP MMBtu volume................................................ 157,764,948
Total impact to industry........................................ $9,470,000 ($.06 x 157,764,948)
----------------------------------------------------------------------------------------------------------------
Benefit-- Reinstatement of Policy Allowing Transportation Allowances
for Deep-Water-Gathering Systems for Federal Oil and Gas
The deep-water-gathering policy discussed previously allows
companies to deduct certain expenses for subsea gathering from their
royalty payments, even though those costs do not meet ONRR's definition
of transportation. This rule would result in ONRR continuing to apply
the policy to the extent that it is consistent with the prior (and
soon-to-be-reinstated) regulations. Lessees would therefore be allowed
to claim additional allowances, which would decrease their royalties
due. To analyze the impact to industry of reinstating this policy, we
used data from BSEE's ArcGIS TIMS (Technical Information Management
System) database to estimate that 113 subsea pipeline segments serving
140 leases currently qualify for an allowance under the policy. We
assumed all segments were the same--in other words, we did not take
into account the size, length, or type of pipeline. For our analysis we
also considered only pipeline segments that were in active status and
leases in producing status. To determine a range (shown in the tables
below as low, mid, and high estimates) for the impact for industry,
ONRR estimated a 15 percent error rate in our identification of the 113
eligible pipeline segments, resulting in a range of 96 to 130 eligible
pipeline segments.
Historical ONRR audit data was available for 13 subsea gathering
segments, which served 15 leases covering time periods from 1999
through 2010. We used this data to determine an average initial amount
of capital investment in pipeline segments. We used the initial capital
investment amount to calculate depreciation and a return on
undepreciated capital investment (ROI) for the eligible pipeline
segments. We calculated depreciation using a 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 at the time we performed this
analysis. We based the calculations for depreciation and ROI on the
first year a pipeline was in service.
From the same audit data, we calculated an average annual operating
and maintenance (O&M) cost. We increased the O&M cost by 12 percent to
account for overhead expenses. Based on experience and audit data, we
assumed that 12 percent is a reasonable increase for overhead. We then
decreased the total annual O&M cost per pipeline segment by nine
percent because an average of nine 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 Gulf of
Mexico. Based on the these calculations, the average annual allowance
per pipeline segment is approximately $226,664. This represents the
estimated amount per pipeline segment ONRR would no longer allow
lessees to take as a transportation allowance based on our rescission
of the Deep Water Policy in this proposed rulemaking.
The total cost to industry would be the $226,664 annual allowance
per pipeline segment that we would allow under this proposed rulemaking
times the number of eligible segments. To calculate a range for this
total, we multiplied the average annual allowance by the low (96), mid
(113), and high (130) number of eligible segments. The low, mid, and
high annual allowance estimates we would allow are $21.8 million, $25.6
million, and $29.5 million, respectively.
Of the currently eligible leases, 56 out of 140, or about 40
percent, qualified for deep water royalty relief under the policy.
However, due to varying lease terms, royalty relief programs, price
thresholds, volume thresholds, litigation, and other factors, ONRR
estimated that only one-half of the 56 leases eligible for royalty
relief (20 percent of the 56) actually received royalty relief.
Therefore, we decreased the low, mid, and high estimated annual benefit
to industry by 20 percent. The table below shows the estimated royalty
impact of this section of the proposed rule based on the allowances we
will allow under this rule.
----------------------------------------------------------------------------------------------------------------
Low Mid High
----------------------------------------------------------------------------------------------------------------
Estimated Royalty Impact..................................... $23,900,000 $28,100,000 $32,300,000
----------------------------------------------------------------------------------------------------------------
Cost--Reinstatement of Policy Allowing Transportation Allowances for
Deep-Water- Gathering Systems for Federal Oil and Gas
We estimate the restoration of transportation allowances for deep-
water-gathering systems would eliminate the industry administrative
benefit under the 2017 Valuation Rule as lessees would have to perform
this calculation. We assume that the cost to perform this calculation
is significant because in our experience industry has often hired
outside consultants to calculate their subsea transportation
allowances. Using this information, we estimate each company with
leases eligible for transportation allowances for deep water gathering
systems would allocate one full-time FTE annually to perform this
calculation, whether they use consultants or perform the calculation
in-house. We used the Bureau of Labor Statistics to estimate the hourly
cost for industry accountants in a metropolitan area ($38.16 mean
hourly wage) with a multiplier of 1.4 for industry benefits to equal
approximately $53.42 per hour ($38.16 x 1.4). Using this labor cost per
hour, we estimate the annual administrative cost to industry would be
approximately:
[[Page 36949]]
----------------------------------------------------------------------------------------------------------------
Companies
Annual burden Industry labor reporting Estimated cost
hours per cost/hour eligible to industry
company leases
----------------------------------------------------------------------------------------------------------------
Deep Water Gathering........................ 2,080 $53.42 32 $3,560,000
----------------------------------------------------------------------------------------------------------------
Benefit--Reinstating Extraordinary Processing Cost Allowances for
Federal Gas
As we discussed previously, we are reinstating the provision in our
regulations that allows lessees to request an extraordinary processing
cost allowance and to allow any extraordinary processing cost
allowances that we previously granted. We have granted two such
approvals in the past, so we know the lease universe that is claiming
this allowance and were able to retrieve the processing allowance data
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 2012 through 2015 for the leases at issue. We
then averaged the yearly totals for those four years to estimate an
annual benefit to industry of $14.2 million in decreased royalties.
Benefit--Increasing the Rate of Return Used To Calculate Non-Arm's-
Length Transportation Allowances From 1 to 1.3 Times the Standard and
Poor's BBB Bond for Federal Oil and Gas
For Federal oil transportation, we do not maintain or request data
identifying whether transportation allowances are arm's length or non-
arm's length. However, in our experience, lessees transport a
significant portion of Gulf of Mexico (GOM) oil through their own
pipelines. In addition, many onshore transportation allowances include
costs of trucking and rail and, most likely, this change would not
impact those. Therefore, to calculate the costs associated with this
change, we assumed that 50 percent of the GOM transportation allowances
are non-arm's length and that ten 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.
In 2015, the total oil transportation allowances that Federal
lessees deducted were approximately $100 million from the GOM and $12.5
million from everywhere else. Based on these totals 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 $16,600,000 for the GOM ($100,000,000 x \1/3\ x 50%) and
$416,000 ($12,500,000 x \1/3\ x 10%) for the rest of the country. Based
on these assumptions, industry will receive an increase in yearly oil
transportation allowance deductions of approximately $3,920,000
($17,000,000 x (1.3 - 1.0)/1.3). That is, we estimate that the net
benefit to industry for oil transportation allowances as a result of
this change will be an approximately $3,920,000 in decreased royalties
due.
Like Federal oil, we do not maintain or request information on
whether Federal gas transportation allowances are arm's-length or non-
arm's length. However, unlike Federal oil, in our experience, 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 that we made for oil.
In 2015, the total gas transportation allowances that Federal
lessees deducted were approximately $238 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 $7.93 million ($238,000,000 x \1/3\ x
10%). Therefore, industry will see an increase in yearly gas
transportation allowance deductions of approximately $1.82 million
($7.93 million x (1.3 - 1.0)/1.3). That is, the net decreased cost to
industry for gas transportation allowances will be approximately
$1,820,000.
The combined impact to industry for this change will be $5,740,000
in decreased royalties due.
No Change--Disallow a Rate of Return on Reasonable Salvage Value for
Federal Oil, Gas, and Coal
In the 2017 Valuation Rule, ONRR estimated that this provision
would have no impact to industry. ONRR likewise estimates that the
repeal has no impact.
Benefit--Allow Line Loss as a Component of Non-Arm's-Length Oil and Gas
Transportation
This rule also reinstates the regulatory provision allowing lessees
to deduct the 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 would also equate 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 2015, the Federal royalty
value subject to transportation allowances was $2,746,256,148 in the
GOM and $1,039,271,142 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 $2.96 million, as we detailed in the
table below. Therefore, the annual benefit to industry will be
approximately $2.96 million.
Oil Line Loss Royalty Impact
----------------------------------------------------------------------------------------------------------------
Royalty
Line loss % decrease
----------------------------------------------------------------------------------------------------------------
50% of GOM royalty value...................................... $1,373,128,209 0.2 $2,750,000
10% of everywhere else royalty value.......................... 103,927,114 0.2 208,000
-------------------------------------------------
[[Page 36950]]
Total..................................................... ................ .............. 2,960,000
----------------------------------------------------------------------------------------------------------------
For Federal gas produced in calendar year 2015, the Federal gas
royalty value subject to transportation allowances was $888,676,828.
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 and annual benefit to industry would be
$178,000.
Gas Line Loss Royalty Impact
----------------------------------------------------------------------------------------------------------------
Royalty
Line loss % decrease
----------------------------------------------------------------------------------------------------------------
10% of royalty value....................................... $88,867,683 0.2 $178,000
----------------------------------------------------------------------------------------------------------------
The total estimated royalty decrease for both oil and gas due to
this change will be $3.14 million [$2,960,000 (oil) plus $178,000 (gas)
= $3,140,000].
Benefit--Depreciating Oil Pipeline Assets Only Once
Under the non-arm's-length transportation allowance section of this
rule and the rule in effect prior to the 2017 Valuation Rule, for
Federal oil, if an oil pipeline is sold, the purchasing company might
use the purchase price to establish a new depreciation schedule,
provided that the purchasing company is a royalty payor claiming a non-
arm's-length transportation allowance. In theory, this change results
in additional royalty savings for companies. However, based on our
experience monitoring the oil markets, we find that the sale of oil
pipeline assets is rare. 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 benefit to industry under this rule, we cannot
quantify the cost at this time.
No Change--Eliminating the Use of the First Arm's-Length Sale to Value
Non-Arm's-Length Sales of Federal Coal and Sales of Federal Coal
Between Parties That Lack Opposing Economic Interest--``Coal
Cooperatives'' in the 2017 Valuation Rule
In the 2017 Valuation Rule, ONRR did not estimate any impacts to
industry for the change in regulations for this provision. This repeal
will reinstate the valuation regulations as they were prior to the 2017
Valuation Rule's publication. Therefore, ONRR does not estimate any
impact to industry at this time.
No Change--Eliminating the Use of Arm's-Length Electricity Sales to
Value Non-Arm's-Length Dispositions of Federal Coal and Dispositions of
Federal Coal Parties That Lack Opposing Economic Interest--``Coal
Cooperatives'' in the 2017 Valuation Rule
In the 2017 Valuation Rule, ONRR did not estimate any impacts to
industry for the change in regulations for this provision. This repeal
will reinstate the valuation regulations as they were prior to the 2017
Valuation Rule's publication. Therefore, ONRR does not estimate any
impact to industry at this time.
No Change--Eliminating the Default Provision to Value Non-Arm's-Length
Sales of Federal Coal in Lieu of Sales of Electricity
For these situations, valuation of Federal coal will be determined
under the non-arm's-length benchmarks after this repeal of the 2017
Valuation Rule. Because the default provision establishes a valuation
method that approximates the market value of the coal very similar to
the benchmarks, we estimate that the royalty effect of this rule on
lessees of Federal coal will be nominal.
No Change--Using the First Arm's-Length Sale to Value Non-Arm's-Length
Sales of Indian Coal
In the 2017 Valuation Rule, ONRR did not estimate any impacts to
industry for the change in regulations for this provision. This repeal
will reinstate the valuation regulations as they were prior to the 2017
Valuation Rule's publication. Therefore, we do not estimate any impact
to industry at this time.
No Change--Using Sales of Electricity to Value Non-Arm's-Length Sales
of Indian Coal
In the 2017 Valuation Rule, ONRR did not estimate any impacts to
industry for the change in regulations for this provision. This repeal
will reinstate the valuation regulations as they were prior to the 2017
Valuation Rule's publication. Therefore, we do not estimate any impact
to industry at this time.
No Change--Using First Arm's-Length Sale to Value Sales of Indian Coal
Between Coal Cooperative Members
In the 2017 Valuation Rule, ONRR did not estimate any impacts to
industry for the change in regulations for this provision. This repeal
will reinstate the valuation regulations as they were prior to the 2017
Valuation Rule's publication. Therefore, we do not estimate any impact
to industry at this time.
No Change--Elimination of the Default Provision to Value Federal Oil,
Gas, and Coal and Indian Coal
In the 2017 Valuation Rule, we anticipated that we would have used
the default provision only in specific cases where conventional
valuation procedures have not worked to establish a value for royalty
purposes. We also stated that assigning a royalty impact figure to any
of the instances where we would have used the default provisions was
speculative because (1) each instance would have been case-specific,
(2) we could not anticipate when we would have used the option, and (3)
we could not anticipate the value that we would have required companies
to pay. Additionally, we estimated that the royalty impact would have
been relatively small because the default provision would always have
established a reasonable value of
[[Page 36951]]
production using market-based transaction data, which has always been
the basis for our royalty valuation rules. Therefore, removal of the
default provision will have a similarly small and speculative royalty
difference.
2. State and Local Governments
We estimate that the States and local governments that this rule
impacts will incur a decrease in royalty receipts. The details of this
impact are outlined below.
States and local governments receiving revenues for offshore Outer
Continental Shelf Lands Act Section 8(g) leases will continue to
receive royalties as under the regulations preceding the 2017 Valuation
Rule, as will States receiving revenues from onshore Federal lands.
Based on the ratio of Federal revenues disbursed to States and local
governments for section 8(g) leases and the onshore States we detail in
the table below, ONRR assumed the same proportion of revenue decreases
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
Section 8(g)................................. 0 0 27
------------------------------------------------------------------------
Some provisions of this rule affect Federal, State, and local
government revenues, while others, such as reinstating extraordinary
processing cost allowances, affect only onshore States' and Federal
revenues. The table summarizing the State and local government royalty
decreases that we provide in section 5 details these differences.
3. Indian Lessors
ONRR estimates that the changes to the coal regulations that apply
to Indian lessors will have no impact on their royalties.
4. Federal Government
The impact to the Federal government, like the States and local
governments, will be a net decrease in royalties as a result of these
changes. The royalty decrease incurred by the Federal government will
be the difference between the total royalty decrease to industry and
the royalty decrease affecting the States and local governments. The
net yearly impact on the Federal government will be approximately $55.8
million, which we detail in section (5) below.
5. Summary of Royalty Impacts and Costs to Industry, State and Local
Governments, Indian Lessors, and the Federal Government
In the table below, the negative values in the industry column
represent their estimated royalty collection decrease for Federal,
State, and local governments, while the positive values in the other
columns represent the increase in royalty savings for industry. Please
note that the estimated impacts to Federal, State, and local
governments do not include the administrative savings provisions of the
economic analysis discussed above. Those provisions are only realized
by industry. For the purposes of this summary table, we used the
midpoint estimates for these impacts.
----------------------------------------------------------------------------------------------------------------
Rule Provision Industry Federal State State 8(g)
----------------------------------------------------------------------------------------------------------------
Gas--restore benchmarks:
Remove affiliate Resale..................... $1,360,000 ($865,000) ($483,000) ($11,600)
Remove index................................ $10,600,000 ($6,750,000) ($3,760,000) ($90,600)
NGLs--restore benchmarks:
Remove affiliate Resale..................... $754,000 ($529,000) ($220,000) ($4,830)
Remove index................................ ($2,210,000) $1,550,000 $646,000 $14,200
Gas transportation 50% limitation exceptions $87,000 ($55,400) ($30,900) ($744)
reinstated.....................................
Processing allowance 66\2/3\% limitation $42,700 ($29,900) ($12,500) ($274)
exceptions reinstated..........................
POP contracts' processing allowance exceptions $9,470,000 ($6,640,000) ($2,770,000) ($60,700)
of 66\2/3\% limitation reinstated..............
Extraordinary processing allowance reinstated... $14,200,000 ($7,100,000) ($7,100,000) $0
Deep-water-gathering reinstated................. $28,100,000 ($28,100,000) $0 $0
Oil transportation 50% limitation exceptions $0 $0 $0 $0
reinstated.....................................
Oil and gas line losses allowance reinstated.... $3,140,000 ($2,560,000) ($562,000) ($17,200)
BBB bond rate change removed.................... $5,740,000 ($4,680,000) ($1,030,000) ($31,500)
Coal provisions................................. $0 $0 $0 $0
---------------------------------------------------------------
Total....................................... $71,300,000 ($55,800,000) ($15,300,000) ($200,000)
----------------------------------------------------------------------------------------------------------------
Note: totals from this table and others in this analysis may not add due to rounding.
B. Regulatory Planning and Review (Executive Orders 12866 and 13563 and
Executive Order 13771 on Reducing Regulation and Controlling Regulatory
Costs Dated January 30, 2017)
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 rules. OIRA has determined
that this rule is significant because it may materially alter the
budgetary impact of entitlements, grants, user fees, or loan programs
or the rights and obligations of recipients thereof.
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.
This final rule is considered a deregulatory action under E.O.
13771, Reducing Regulation and Controlling Regulatory Costs (82 FR
9339, Feb. 3, 2017). Although there are some costs to industry
associated with this rule, the
[[Page 36952]]
rule still results in an overall savings to industry. Details on the
estimated savings and costs associated with the rule can be found in
the rule's economic analysis.
C. Regulatory Flexibility Act
The Department of the Interior (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 the 2017 Valuation Rule, Procedural Matters, item 1,
starting at 81 FR 43359, and item 3, starting at 81 FR 43367.
This rule will affect only lessees under Federal oil and gas leases
and Federal and Indian coal leases.
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 2015 sales data, this rule is a
benefit to industry of approximately $71 million dollars per year.
Small businesses accounted for about 20 percent of the royalties paid
in 2015. Applying that percentage to industry costs, we estimate that
this final rule will benefit all small-business lessors approximately
$14,200,000 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 benefit affected small businesses a collective
total of $14,200,000 per year.
D. 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:
(1) Does not have an annual effect on the economy of $100 million
or more. We estimate that industry will annually benefit between
$60,100,000 and $74,800,000. These figures are a reversal of the
impacts described in the 2017 Valuation Rule, under Procedural Matters,
item 1, starting at 81 FR 43359, and item 4, 81 FR 43368, but has been
adjusted to include more current data. Therefore, the economic impact
on industry, State and local governments and the Federal government
will be below the $100 million threshold that the Federal government
uses to define a rule as having a significant impact on the economy.
(2) Will not cause a major increase in costs or prices for
consumers; individual industries; Federal, State, or local government
agencies; or geographic regions. See Procedural Matters, item 1.
(3) 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. This
rule will benefit U.S.-based enterprises.
E. 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. Therefore, 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. See
Procedural Matters, item 1.
F. 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.
G. 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 assessment. The management of Federal oil and gas leases,
and Federal and Indian coal leases is the responsibility of the
Secretary of the Interior. 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.
H. Civil Justice Reform (E.O. 12988)
This rule complies with the requirements of E.O. 12988.
Specifically, this rule:
(a) Meets the criteria of Sec. 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 Sec. 3(b)(2), which requires that we
write all regulations in clear language using clear legal standards.
I. Consultation With Indian Tribes (E.O. 13175 and Departmental Policy)
The Department strives to strengthen its government-to-government
relationship with Indian Tribes through a commitment to consultation
with Indian Tribes and recognition of their right to self-governance
and Tribal sovereignty. Under the criteria in E.O. 13175, we evaluated
this final rule and determined that it will have no potential effects
on Federally-recognized Indian Tribes. Specifically, we determined that
this rule will restore the historical valuation methodology for coal
produced from Indian leases. Accordingly:
(1) We mailed letters, on April 3, 2017, to the Crow Tribe of
Montana, Hopi Tribe of Arizona, and Navajo Nation to consult with the
Tribes on both the Notice of Proposed Rulemaking and Advance Notice of
Proposed Rulemaking for the proposed repeal of 2017 Indian coal
valuation regulations.
(2) We consulted with the Navajo Nation on May 24, 2017, in Window
Rock, Arizona.
(3) We consulted with the Crow Tribe on May 26, 2017, in Crow
Agency, Montana.
(4) We consulted with the Hopi on June 21, 2017, in Kykotsmovi,
Arizona.
[[Page 36953]]
J. Paperwork Reduction Act
This rule:
(1) Does not contain any new information collection requirements.
(2) Does not require a submission to the OMB under the Paperwork
Reduction Act of 1995 (44 U.S.C. 3501 et seq.). See 5 CFR 1320.4(a)(2).
This rule will leave intact the information collection requirements
that OMB already approved under OMB Control Numbers 1012-0004, 1012-
0005, and 1012-0010.
K. 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(i) in that this is ``. . . of an
administrative, financial, legal, technical, or procedural nature. . .
.'' This rule also qualifies for categorically exclusion under
Departmental Manual, part 516, section 15.4.(C)(1) in that its impacts
are limited to administrative, economic, or technological effects. 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 the
repeal of the 2017 Valuation Rule will have no consequence on the
physical environment. This rule does not alter, in any material way,
natural resources exploration, production, or transportation.
L. 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
30 CFR Part 1202
Coal, Continental shelf, Government contracts, Indian lands,
Mineral royalties, Natural gas, Oil and gas exploration, Public lands--
mineral resources, Reporting and recordkeeping requirements.
30 CFR Part 1206
Coal, Continental shelf, Government contracts, Indian lands,
Mineral royalties, Oil and gas exploration, Public lands--mineral
resources, Reporting and recordkeeping requirements.
Gregory J. Gould,
Director for Office of Natural Resources Revenue.
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 subparts B, C, D, and E of part 1206 of this
title are applicable to subparts B, C, D, and J of this part.
Subpart F--Coal
0
3. Remove Sec. 1202.251.
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, consisting of Sec. 1206.10, to read as follows:
Subpart A--General Provisions and Definitions
Sec. [thinsp]1206.10 Information collection.
The information collection requirements contained in this part have
been approved by the Office of Management and Budget (OMB) under 44
U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance
numbers are identified in Sec. [thinsp]1210.10.
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 What definitions apply to this subpart?
1206.102 How do I calculate royalty value for oil that I or my
affiliate sell(s) under an arm's-length contract?
1206.103 How do I value oil that is not sold under an arm's-length
contract?
1206.104 What publications are acceptable to ONRR?
1206.105 What records must I keep to support my calculations of
value under this subpart?
1206.106 What are my responsibilities to place production into
marketable condition and to market production?
1206.107 How do I request a value determination?
1206.108 Does ONRR protect information I provide?
1206.109 When may I take a transportation allowance in determining
value?
1206.110 How do I determine a transportation allowance under an
arm's-length transportation contract?
1206.111 How do I determine a transportation allowance if I do not
have an arm's-length transportation contract or arm's-length tariff?
1206.112 What adjustments and transportation allowances apply when I
value oil production from my lease using NYMEX prices or ANS spot
prices?
1206.113 How will ONRR identify market centers?
1206.114 What are my reporting requirements under an arm's-length
transportation contract?
1206.115 What are my reporting requirements under a non-arm's-length
transportation arrangement?
1206.116 What interest applies if I improperly report a
transportation allowance?
1206.117 What reporting adjustments must I make for transportation
allowances?
1206.119 How are the royalty quantity and quality determined?
1206.120 How are operating allowances determined?
Subpart C--Federal Oil
Sec. [thinsp]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 Outer Continental Shelf (OCS). It
explains how you as a lessee must calculate the value of production for
royalty purposes consistent with the 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
[[Page 36954]]
must determine and report royalty value for the lessee's oil by
applying the rules in this subpart to the lessee's disposition of its
oil.
(d) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee
resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the ONRR Director
establishing a method to determine the value of production from any
lease that ONRR expects at least would approximate the value
established under this subpart; or
(4) An express provision of an oil and gas lease subject to this
subpart, then the statute, settlement agreement, written agreement, or
lease provision will govern to the extent of the inconsistency.
(e) ONRR may audit and adjust all royalty payments.
Sec. [thinsp]1206.101 What definitions apply to this subpart?
The following definitions apply to this subpart:
Affiliate means a person who controls, is controlled by, or is
under common control with another person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the
voting securities, or instruments of ownership, or other forms of
ownership, of another person constitutes control. Ownership of less
than 10 percent constitutes a presumption of noncontrol that ONRR may
rebut.
(2) If there is ownership or common ownership of 10 through 50
percent of the voting securities or instruments of ownership, or other
forms of ownership, of another person, ONRR will consider the following
factors in determining whether 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,
whether a person is the greatest single owner, or whether there is an
opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, or other facility;
(iv) The extent of participation by other owners in operations and
day-to-day management of a lease, plant, or other facility; and
(v) Other evidence of power to exercise control over or common
control with another person.
(3) Regardless of any percentage of ownership or common ownership,
relatives, either by blood or marriage, are affiliates.
ANS means Alaska North Slope (ANS).
Area means a geographic region at least as large as the limits of
an oil field, in which oil has similar quality, economic, and legal
characteristics.
Arm's-length contract means a contract or agreement between
independent persons who are not affiliates and who have opposing
economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this
definition for that month, as well as when the contract was executed.
Audit means a review, conducted under generally accepted accounting
and auditing standards, of royalty payment compliance activities of
lessees, designees or other persons who pay royalties, rents, or
bonuses on Federal leases.
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.
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.
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 the lessee designates to report and pay
the lessee's royalties for a lease.
Exchange agreement means an agreement where one person agrees to
deliver oil to another person at a specified location in exchange for
oil deliveries at another location. Exchange agreements may or may not
specify prices for the oil involved. They frequently specify dollar
amounts reflecting location, quality, or other differentials. Exchange
agreements include buy/sell agreements, which specify prices to be paid
at each exchange point and may appear to be two separate sales within
the same agreement. Examples of other types of exchange agreements
include, but are not limited to, exchanges of produced oil for specific
types of crude oil (e.g., West Texas Intermediate); exchanges of
produced oil for other crude oil at other locations (Location Trades);
exchanges of produced oil for other grades of oil (Grade Trades); and
multi-party exchanges.
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.
Gathering means the movement of lease production to a central
accumulation or treatment point on the lease, unit, or communitized
area, or to a central accumulation or treatment point off the lease,
unit, or communitized area that BLM or BSEE approves for onshore and
offshore leases, respectively.
Gross proceeds means the total monies and other consideration
accruing for the disposition of oil produced. Gross proceeds also
include, but are not limited to, the following examples:
(1) Payments for services such as dehydration, marketing,
measurement, or gathering which the lessee must perform at no cost to
the Federal Government;
(2) The value of services, such as salt water disposal, that the
producer normally performs but that the buyer performs on the
producer's behalf;
(3) Reimbursements for harboring or terminaling fees;
(4) Tax reimbursements, even though the Federal royalty interest
may be exempt from taxation;
(5) Payments made to reduce or buy down the purchase price of oil
to be produced in later periods, by allocating such payments over the
production whose price the payment reduces and including the allocated
amounts as proceeds for the production as it occurs; and
(6) Monies and all other consideration to which a seller is
contractually or legally entitled, but does not seek to collect through
reasonable efforts.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States under a
mineral leasing law that authorizes exploration for, development or
extraction of, or
[[Page 36955]]
removal of oil or gas--or the land area covered by that authorization,
whichever the context requires.
Lessee means any person to whom the United States issues an oil and
gas lease, an assignee of all or a part of the record title interest,
or any person to whom operating rights in a lease have been assigned.
Location differential means an amount paid or received (whether in
money or in barrels of oil) under an exchange agreement that results
from differences in location between oil delivered in exchange and oil
received in the exchange. A location differential may represent all or
part of the difference between the price received for oil delivered and
the price paid for oil received under a buy/sell exchange agreement.
Market center means a major point ONRR recognizes for oil sales,
refining, or transshipment. Market centers generally are locations
where ONRR-approved publications publish oil spot prices.
Marketable condition means oil sufficiently free from impurities
and otherwise in a condition a purchaser will accept under a sales
contract typical for the field or area.
Netting means reducing the reported sales value to account for
transportation instead of reporting a transportation allowance as a
separate entry on form ONRR-2014.
NYMEX price means the average of the New York Mercantile Exchange
(NYMEX) settlement prices for light sweet crude oil delivered at
Cushing, Oklahoma, calculated as follows:
(1) Sum the prices published for each day during the calendar month
of production (excluding weekends and holidays) for oil to be delivered
in the prompt month corresponding to each such day; and
(2) Divide the sum by the number of days on which those prices are
published (excluding weekends and holidays).
Oil means a mixture of hydrocarbons that existed in the liquid
phase in natural underground reservoirs, remains liquid at atmospheric
pressure after passing through surface separating facilities, and is
marketed or used as a liquid. Condensate recovered in lease separators
or field facilities is oil.
ONRR-approved publication means a publication ONRR approves for
determining ANS spot prices or WTI differentials.
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.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
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.
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
March. March was the prompt month (for year 2003) from January 22
through February 20. April was the first month following the month of
production, and May was the second month following the month of
production. P0 therefore is the average of the daily NYMEX
settlement prices for deliveries during March published for each
business day between January 22 and February 20. P1 is the
average of the daily NYMEX settlement prices for deliveries during
April published for each business day between January 22 and February
20. P2 is the average of the daily NYMEX settlement prices
for deliveries during May published for each business day between
January 22 and February 20. In this example, assume that P0
= $28.00 per bbl, P1 = $27.70 per bbl, and P2 =
$27.10 per bbl. In this example (a declining market), Roll = .6667 x
($28.00 - $27.70) + .3333 x ($28.00 - $27.10) = $.20 + $.30 = $.50. 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 July.
July 2003 was the prompt month from May 21 through June 20. August was
the first month following the month of production, and September was
the second month following the month of production. P0
therefore is the average of the daily NYMEX settlement prices for
deliveries during July published for each business day between May 21
and June 20. P1 is the average of the daily NYMEX settlement
prices for deliveries during August published for each business day
between May 21 and June 20. P2 is the average of the daily
NYMEX settlement prices for deliveries during September published for
each business day between May 21 and June 20. In this example, assume
that P0 = $28.00 per bbl, P1 = $28.90 per bbl,
and P2 = $29.50 per bbl. In this example (a rising market),
Roll = .6667 x ($28.00-$28.90) + .3333 x ($28.00 - $29.50) = (-$.60) +
(-$.50) = -$1.10. You add this negative number to the NYMEX price
(effectively a subtraction from the NYMEX price).
Sale means a contract between two persons where:
(1) The seller unconditionally transfers title to the oil to the
buyer and does not retain any related rights such as the right to buy
back similar quantities of oil from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil; and
(3) The parties' intent is for a sale of the oil to occur.
Spot price means the price under a spot sales contract where:
(1) A seller agrees to sell to a buyer a specified amount of oil at
a specified price over a specified period of short duration;
(2) No cancellation notice is required to terminate the sales
agreement; and
[[Page 36956]]
(3) There is no obligation or implied intent to continue to sell in
subsequent periods.
Tendering program means a producer's offer of a portion of its
crude oil produced from a field or area for competitive bidding,
regardless of whether the production is offered or sold at or near the
lease or unit or away from the lease or unit.
Trading month means the period extending from the second business
day before the 25th day of the second calendar month preceding the
delivery month (or, if the 25th day of that month is a non-business
day, the second business day before the last business day preceding the
25th day of that month) through the third business day before the 25th
day of the calendar month preceding the delivery month (or, if the 25th
day of that month is a non-business day, the third business day before
the last business day preceding the 25th day of that month), unless the
NYMEX publishes a different definition or different dates on its
official Web site, www.nymex.com, in which case the NYMEX definition
will apply.
Transportation allowance means a deduction in determining royalty
value for the reasonable, actual costs of moving oil to a point of sale
or delivery off the lease, unit area, or communitized area. The
transportation allowance does not include gathering costs.
WTI 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.
(1) Example. Assume the production month was March 2003. Industry
trade publications performed their price surveys and determined
differentials during January 26 through February 25 for oil delivered
in March. The WTI differential (for example, the West Texas Sour crude
at Midland, Texas, spread versus WTI) applicable to valuing oil
produced in the March 2003 production month would be determined using
all the business days for which differentials were published during the
period January 26 through February 25 excluding weekends and holidays
(22 days). To calculate the WTI differential, add together all of the
daily mean differentials published for January 26 through February 25
and divide that sum by 22.
(2) [Reserved]
Sec. [thinsp]1206.102 How do I calculate royalty value for oil that I
or my affiliate sell(s) under an arm's-length contract?
(a) The value of oil under this section is the gross proceeds
accruing to the seller under the arm's-length contract, less applicable
allowances determined under Sec. [thinsp]1206.110 or Sec.
[thinsp]1206.111. This value does not apply if you exercise an option
to use a different value provided in paragraph (d)(1) or (d)(2)(i) of
this section, or if one of the exceptions in paragraph (c) of this
section applies. Use this paragraph (a) to value oil that:
(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
(d)(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) This paragraph contains exceptions to the valuation rule in
paragraph (a) of this section. Apply these exceptions on an individual
contract basis.
(1) In conducting reviews and audits, if ONRR determines that any
arm's-length sales contract does not reflect the total consideration
actually transferred either directly or indirectly from the buyer to
the seller, ONRR may require that you value the oil sold under that
contract either under Sec. [thinsp]1206.103 or at the total
consideration received.
(2) You must value the oil under Sec. [thinsp]1206.103 if ONRR
determines that the value under paragraph (a) of this section does not
reflect the reasonable value of the production due to either:
(i) Misconduct by or between the parties to the arm's-length
contract; or
(ii) Breach of your duty to market the oil for the mutual benefit
of yourself and the lessor.
(A) ONRR will not use this provision to simply substitute its
judgment of the market value of the oil for the proceeds received by
the seller under an arm's-length sales contract.
(B) The fact that the price received by the seller under an arm's-
length contract is less than other measures of market price, such as
index prices, is insufficient to establish breach of the duty to market
unless ONRR finds additional evidence that the seller acted
unreasonably or in bad faith in the sale of oil from the lease.
(d)(1) If you enter into an arm's-length exchange agreement, or
multiple sequential arm's-length exchange agreements, and following the
exchange(s) you or your affiliate sell(s) the oil received in the
exchange(s) under an arm's-length contract, then you may use either
Sec. [thinsp]1206.102(a) or Sec. [thinsp]1206.103 to value your
production for royalty purposes.
(i) If you use Sec. [thinsp]1206.102(a), your gross proceeds are
the gross proceeds under your or your affiliate's arm's-length sales
contract after the exchange(s) occur(s). You must adjust your gross
proceeds for any location or quality differential, or other
adjustments, you received or paid under the arm's-length exchange
agreement(s). If ONRR determines that any arm's-length exchange
agreement does not reflect reasonable location or quality
differentials, ONRR may require you to value the oil under Sec.
[thinsp]1206.103. 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. [thinsp]1206.102(d)(1) to use Sec.
[thinsp]1206.102(a) or Sec. [thinsp]1206.103, you must make the same
election for all of your production from the same unit, communitization
agreement, or lease (if the lease is not part of a unit or
communitization agreement) sold under arm's-length contracts following
arm's-length exchange agreements. You may not change your election more
often than once every 2 years.
(2)(i) If you sell or transfer your oil production to your
affiliate and that affiliate or another affiliate then sells the oil
under an arm's-length contract, you may use either Sec.
[thinsp]1206.102(a) or Sec. [thinsp]1206.103 to value your production
for royalty purposes.
(ii) When you elect under Sec. [thinsp]1206.102(d)(2)(i) to use
Sec. [thinsp]1206.102(a) or Sec. [thinsp]1206.103, you must make the
same election for all of your production from the same unit,
communitization agreement, or lease (if the lease is not part of a unit
or communitization agreement) that your affiliates resell at arm's
length. You may not change your election more often than once every 2
years.
(e) If you value oil under paragraph (a) of this section:
(1) ONRR may require you to certify that your or your affiliate's
arm's-length
[[Page 36957]]
contract provisions include all of the consideration the buyer must
pay, either directly or indirectly, for the oil.
(2) You must base value on the highest price the seller can receive
through legally enforceable claims under the contract.
(i) If the seller fails to take proper or timely action to receive
prices or benefits it is entitled to, you must pay royalty at a value
based upon that obtainable price or benefit. But you will owe no
additional royalties unless or until the seller receives monies or
consideration resulting from the price increase or additional benefits,
if:
(A) The seller makes timely application for a price increase or
benefit allowed under the contract;
(B) The purchaser refuses to comply; and
(C) The seller takes reasonable documented measures to force
purchaser compliance.
(ii) Paragraph (e)(2)(i) of this section will not permit you to
avoid your royalty payment obligation where a purchaser fails to pay,
pays only in part, or pays late. Any contract revisions or amendments
that reduce prices or benefits to which the seller is entitled must be
in writing and signed by all parties to the arm's-length contract.
Sec. [thinsp]1206.103 How do I value oil that is not sold under an
arm's-length contract?
This section explains how to value oil that you may not value under
Sec. [thinsp]1206.102 or that you elect under Sec.
[thinsp]1206.102(d) to value under this section. First determine
whether paragraph (a), (b), or (c) of this section applies to
production from your lease, or whether you may apply paragraph (d) or
(e) with ONRR approval.
(a) Production from leases in California or Alaska. Value is the
average of the daily mean ANS spot prices published in any ONRR-
approved publication during the trading month most concurrent with the
production month. (For example, if the production month is June,
compute the average of the daily mean prices using the daily ANS spot
prices published in the ONRR-approved publication for all the business
days in June.)
(1) To calculate the daily mean spot price, average the daily high
and low prices for the month in the selected publication.
(2) 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. [thinsp]1206.112.
(4) After you select an ONRR-approved publication, you may not
select a different publication more often than once every 2 years,
unless the publication you use is no longer published or ONRR revokes
its approval of the publication. If you are required to change
publications, you must begin a new 2-year period.
(b) Production from leases in the Rocky Mountain Region. This
paragraph provides methods and options for valuing your production
under different factual situations. You must consistently apply
paragraph (b)(1), (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.
[thinsp]1206.102 or that you elect under Sec. [thinsp]1206.102(d) to
value under this section.
(1) If you have an ONRR-approved tendering program, you must value
oil produced from leases in the area the tendering program covers at
the highest winning bid price for tendered volumes.
(i) The minimum requirements for ONRR to approve your tendering
program are:
(A) You must offer and sell at least 30 percent of your or your
affiliates' production from both Federal and non-Federal leases in the
area under your tendering program; and
(B) You must receive at least three bids for the tendered volumes
from bidders who do not have their own tendering programs that cover
some or all of the same area.
(ii) If you do not have an ONRR-approved tendering program, you may
elect to value your oil under either paragraph (b)(2) or (3) of this
section. After you select either paragraph (b)(2) or (3) of this
section, you may not change to the other method more often than once
every 2 years, unless the method you have been using is no longer
applicable and you must apply the other paragraph. If you change
methods, you must begin a new 2-year period.
(2) Value is the volume-weighted average of the gross proceeds
accruing to the seller under your or your affiliates' 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 affiliates' 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 affiliates' 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. [thinsp]1206.112.
(4) If you demonstrate to ONRR's satisfaction that paragraphs
(b)(1) through (b)(3) of this section result in an unreasonable value
for your production as a result of circumstances regarding that
production, the ONRR Director may establish an alternative valuation
method.
(c) Production from leases not located in California, Alaska, or
the Rocky Mountain Region. (1) Value is the NYMEX price, plus the roll,
adjusted for applicable location and quality differentials and
transportation costs under Sec. [thinsp]1206.112.
(2) If the ONRR Director determines that use of the roll no longer
reflects prevailing industry practice in crude oil sales contracts or
that) the most common formula used by industry to calculate the roll
changes, ONRR may terminate or modify use of the roll under paragraph
(c)(1) of this section at the end of each 2-year period following July
6, 2004, through notice published in the Federal Register not later
than 60 days before the end of the 2-year period. ONRR will explain the
rationale for terminating or modifying the use of the roll in this
notice.
(d) Unreasonable value. If ONRR determines that the NYMEX price or
ANS spot price does not represent a reasonable royalty value in any
particular case, ONRR may establish reasonable royalty value based on
other relevant matters.
(e) Production delivered to your refinery and the NYMEX price or
ANS spot price is an unreasonable value. (1) Instead of valuing your
production under paragraph (a), (b), or (c) of this section, you may
apply to the ONRR Director to establish a value representing the market
at the refinery if:
(i) You transport your oil directly to your or your affiliate's
refinery, or exchange your oil for oil delivered to your or your
affiliate's refinery; and
(ii) You must value your oil under this section at the NYMEX price
or ANS spot price; and
(iii) You believe that use of the NYMEX price or ANS spot price
results in an unreasonable royalty value.
(2) You must provide adequate documentation and evidence
demonstrating the market value at the refinery. That evidence may
include, but is not limited to:
[[Page 36958]]
(i) Costs of acquiring other crude oil at or for the refinery;
(ii) How adjustments for quality, location, and transportation were
factored into the price paid for other oil;
(iii) Volumes acquired for and refined at the refinery; and
(iv) Any other appropriate evidence or documentation that ONRR
requires.
(3) If the ONRR Director establishes a value representing market
value at the refinery, you may not take an allowance against that value
under Sec. [thinsp]1206.112(b) unless it is included in the Director's
approval.
Sec. [thinsp]1206.104 What publications are acceptable to ONRR?
(a) ONRR periodically will publish in the Federal Register a list
of acceptable publications for the NYMEX price and ANS spot price based
on certain criteria, including, but not limited to:
(1) Publications buyers and sellers frequently use;
(2) Publications frequently mentioned in purchase or sales
contracts;
(3) Publications that use adequate survey techniques, including
development of estimates based on daily surveys of buyers and sellers
of crude oil, and, for ANS spot prices, buyers and sellers of ANS crude
oil; and
(4) Publications independent from ONRR, other lessors, and lessees.
(b) Any publication may petition ONRR to be added to the list of
acceptable publications.
(c) ONRR will specify the tables you must use in the acceptable
publications.
(d) ONRR may revoke its approval of a particular publication if it
determines that the prices or differentials published in the
publication do not accurately represent NYMEX prices or differentials
or ANS spot market prices or differentials.
Sec. [thinsp]1206.105 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 be able to show:
(1) How you calculated the value you reported, including all
adjustments for location, quality, and transportation, and
(2) How you complied with these rules.
(b) Recordkeeping requirements are found at part 1207 of this
chapter.
(c) ONRR may review and audit your data, and ONRR will direct you
to use a different value if it determines that the reported value is
inconsistent with the requirements of this subpart.
Sec. [thinsp]1206.106 What are my responsibilities to place
production into marketable condition and to market production?
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. 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. [thinsp]1206.107 How do I request a value determination?
(a) You may request a value determination from ONRR regarding any
Federal lease oil production. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, the record title or
operating rights owners of those leases, and the designees 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) ONRR will reply to requests expeditiously. ONRR may either:
(1) Issue a value determination signed by the Assistant Secretary,
Policy, Management and Budget; or
(2) Issue a value determination by ONRR; or
(3) Inform you in writing that ONRR will not provide a value
determination. Situations in which ONRR typically will not provide any
value determination include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or
administrative appeals.
(c)(1) A value determination signed by the Assistant Secretary,
Policy, Management and Budget, is binding on both you and ONRR until
the Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a value determination, you
must make any adjustments in royalty payments that follow from the
determination and, if you owe additional royalties, pay late payment
interest under Sec. 1218.54 of this chapter.
(3) A value determination signed by the Assistant Secretary is the
final action of the Department and is subject to judicial review under
5 U.S.C. 701-706.
(d) A value determination issued by ONRR is binding on ONRR and
delegated States with respect to the specific situation addressed in
the determination unless the ONRR (for ONRR-issued value
determinations) or the Assistant Secretary modifies or rescinds it.
(1) A value determination by ONRR is not an appealable decision or
order under 30 CFR part 1290.
(2) If you receive an order requiring you to pay royalty on the
same basis as the value determination, you may appeal that order under
30 CFR part 1290.
(e) In making a value determination, ONRR or the Assistant
Secretary may use any of the applicable valuation criteria in this
subpart.
(f) A change in an applicable statute or regulation on which any
value determination is based takes precedence over the value
determination, regardless of whether the ONRR or the Assistant
Secretary modifies or rescinds the value determination.
(g) The ONRR or the Assistant Secretary generally will not
retroactively modify or rescind a value determination issued under
paragraph (d) of this section, unless:
(1) There was a misstatement or omission of material facts; or
(2) The facts subsequently developed are materially different from
the facts on which the guidance was based.
(h) ONRR may make requests and replies under this section available
to the public, subject to the confidentiality requirements under Sec.
1206.108.
Sec. 1206.108 Does ONRR protect information I provide?
Certain information you submit to ONRR regarding valuation of oil,
including transportation allowances, may be exempt from disclosure. To
the extent applicable laws and regulations permit, ONRR will keep
confidential any data you submit that is privileged, confidential, or
otherwise exempt from disclosure. All requests for information must be
submitted under the Freedom of Information Act regulations of the
Department of the Interior at 43 CFR part 2.
Sec. 1206.109 When may I take a transportation allowance in
determining value?
(a) Transportation allowances permitted when value is based on
gross proceeds. ONRR will allow a deduction
[[Page 36959]]
for the reasonable, actual costs to transport oil from the lease to the
point off the lease under Sec. 1206.110 or Sec. 1206.111, as
applicable. This paragraph applies when:
(1) You value oil under Sec. 1206.102 based on gross proceeds from
a sale at a point off the lease, unit, or communitized area where the
oil is produced, and
(2) The movement to the sales point is not gathering.
(b) Transportation allowances and other adjustments that apply when
value is based on NYMEX prices or ANS spot prices. If you value oil
using NYMEX prices or ANS spot prices under Sec. 1206.103, ONRR will
allow an adjustment for certain location and quality differentials and
certain costs associated with transporting oil as provided under Sec.
1206.112.
(c) Limits on transportation allowances. (1) Except as provided in
paragraph (c)(2) of this section, your transportation allowance may not
exceed 50 percent of the value of the oil as determined under Sec.
1206.102 or Sec. 1206.103 of this subpart. You may not use
transportation costs incurred to move a particular volume of production
to reduce royalties owed on production for which those costs were not
incurred.
(2) You may ask ONRR to approve a transportation allowance in
excess of the limitation in paragraph (c)(1) of this section. You must
demonstrate that the transportation costs incurred were reasonable,
actual, and necessary. Your application for exception (using form ONRR-
4393, Request to Exceed Regulatory Allowance Limitation) must contain
all relevant and supporting documentation necessary for ONRR to make a
determination. You may never reduce the royalty value of any production
to zero.
(d) Allocation of transportation costs. You must allocate
transportation costs among all products produced and transported as
provided in Sec. Sec. 1206.110 and 1206.111. You must express
transportation allowances for oil as dollars per barrel.
(e) Liability for additional payments. If ONRR determines that you
took an excessive transportation allowance, then you must pay any
additional royalties due, plus interest under Sec. 1218.54 of this
chapter. You also could be entitled to a credit with interest under
applicable rules if you understated your transportation allowance. If
you take a deduction for transportation on form ONRR-2014 by improperly
netting the allowance against the sales value of the oil instead of
reporting the allowance as a separate entry, ONRR may assess you an
amount under Sec. 1206.116.
Sec. 1206.110 How do I determine a transportation allowance under an
arm's-length transportation contract?
(a) 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
paragraphs (a)(1) and (2) of this section and subject to the limitation
in Sec. 1206.109(c). You must be able to demonstrate that your or your
affiliate's contract is at arm's length. You do not need ONRR approval
before reporting a transportation allowance for costs incurred under an
arm's-length transportation contract.
(1) If ONRR determines that the contract reflects more than the
consideration actually transferred either directly or indirectly from
you or your affiliate to the transporter for the transportation, ONRR
may require that you calculate the transportation allowance under Sec.
1206.111.
(2) You must calculate the transportation allowance under Sec.
1206.111 if ONRR determines that the consideration paid under an arm's-
length transportation contract does not reflect the reasonable value of
the transportation due to either:
(i) Misconduct by or between the parties to the arm's-length
contract; or
(ii) Breach of your duty to market the oil for the mutual benefit
of yourself and the lessor.
(A) ONRR will not use this provision to simply substitute its
judgment of the reasonable oil transportation costs incurred by you or
your affiliate under an arm's-length transportation contract.
(B) The fact that the cost you or your affiliate incur in an arm's-
length transaction is higher than other measures of transportation
costs, such as rates paid by others in the field or area, is
insufficient to establish breach of the duty to market unless ONRR
finds additional evidence that you or your affiliate acted unreasonably
or in bad faith in transporting oil from the lease.
(b) You may deduct any of the following actual costs you (including
your affiliates) incur for transporting oil. You may not use as a
deduction any cost that duplicates all or part of any other cost that
you use under this paragraph.
(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) The cost of carrying on your books as inventory a volume of oil
that the pipeline operator requires you to maintain, and that you do
maintain, in the line as line fill. You must calculate this cost as
follows:
(i) 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. 1206.102 or Sec.
1206.103, as applicable; and
(ii) Multiply the value calculated under paragraph (b)(4)(i) of
this section by the monthly rate of return, calculated by dividing the
rate of return specified in Sec. 1206.111(i)(2) by 12.
(5) Fees paid to a terminal operator for loading and unloading of
crude oil into or from a vessel, vehicle, pipeline, or other
conveyance.
(6) Fees paid for short-term storage (30 days or less) incidental
to transportation as required by a transporter.
(7) Fees paid to pump oil to another carrier's system or vehicles
as required under a tariff.
(8) 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.
(9) 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.
(10) Costs of securing a letter of credit, or other surety, that
the pipeline requires you as a shipper to maintain.
(c) You may not deduct any costs that are not actual costs of
transporting oil, including but not limited to the following:
(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 your arm's-length transportation contract includes more than
one liquid
[[Page 36960]]
product, and the transportation costs attributable to each product
cannot be determined from the contract, then you must allocate the
total transportation costs to each of the liquid products transported.
(1) 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 liquid products (excluding waste products with no
value).
(2) You may not claim an allowance for the costs of transporting
lease production that is not royalty-bearing.
(3) You may propose to ONRR a cost allocation method on the basis
of the values of the products transported. ONRR will approve the method
unless it is not consistent with the purposes of the regulations in
this subpart.
(e) If your arm's-length transportation contract includes both
gaseous and liquid products, and the transportation costs attributable
to each product cannot be determined from the contract, then you must
propose an allocation procedure to ONRR.
(1) You may use your proposed procedure to calculate a
transportation allowance until ONRR accepts or rejects your cost
allocation. If ONRR rejects your cost allocation, you must amend your
form ONRR-2014 for the months that you used the rejected method and pay
any additional royalty and interest due.
(2) You must submit your initial proposal, including all available
data, within 3 months after first claiming the allocated deductions on
form ONRR-2014.
(f) If your payments for transportation under an arm's-length
contract are not on a dollar-per-unit basis, you must convert whatever
consideration is paid to a dollar-value equivalent.
(g) If your arm's-length sales contract includes a provision
reducing the contract price by a transportation factor, do not
separately report the transportation factor as a transportation
allowance on form ONRR-2014.
(1) You may use the transportation factor in determining your gross
proceeds for the sale of the product.
(2) You must obtain ONRR approval before claiming a transportation
factor in excess of 50 percent of the base price of the product.
Sec. 1206.111 How do I determine a transportation allowance if I do
not have an arm's-length transportation contract or arm's-length
tariff?
(a) This section applies if you or your affiliate do 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 include the following:
(1) Operating and maintenance expenses under paragraphs (d) and (e)
of this section;
(2) Overhead under paragraph (f) of this section;
(3) Depreciation under paragraphs (g) and (h) of this section;
(4) A return on undepreciated capital investment under paragraph
(i) of this section; and
(5) Once the transportation system has been depreciated below ten
percent of total capital investment, a return on ten percent of total
capital investment under paragraph (j) of this section.
(6) To the extent not included in costs identified in paragraphs
(d) through (j) of this section, you may also deduct the following
actual costs. You may not use any cost as a deduction that duplicates
all or part of any other cost that you use under this section:
(i) Volumetric adjustments for actual (not theoretical) line
losses.
(ii) 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) 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. 1206.102 or Sec.
1206.103, as applicable; and
(B) Multiply the value calculated under paragraph (b)(6)(ii)(A) of
this section by the monthly rate of return, calculated by dividing the
rate of return specified in Sec. 1206.111(i)(2) by 12.
(iii) 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.
(iv) 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.
(v) 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.
(vi) Fees paid to a non-affiliated quality bank administrator for
administration of a quality bank.
(7) You may not deduct any costs that are not actual costs of
transporting oil, including but not limited to the following:
(i) Fees paid for long-term storage (more than 30 days).
(ii) Administrative, handling, and accounting fees associated with
terminalling.
(iii) Title and terminal transfer fees.
(iv) Fees paid to track and match receipts and deliveries at a
market center or to avoid paying title transfer fees.
(v) Fees paid to brokers.
(vi) Fees paid to a scheduling service provider.
(vii) 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.
(viii) Theoretical line losses.
(ix) Gauging fees.
(c) Allowable capital costs are generally those for depreciable
fixed assets (including costs of delivery and installation of capital
equipment) which are an integral part of the transportation system.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating expense
which you can document.
(e) Allowable maintenance expenses include:
(1) Maintenance of the transportation system;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses
which you can document.
(f) 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.
(g) To compute depreciation, you may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services, or a
unit-of-production method. After you make an election, you may not
change methods without
[[Page 36961]]
ONRR approval. You may not depreciate equipment below a reasonable
salvage value.
(h) This paragraph describes the basis for your depreciation
schedule.
(1) If you or your affiliate own a transportation system on June 1,
2000, you must base your depreciation schedule used in calculating
actual transportation costs for production after June 1, 2000, on your
total capital investment in the system (including your original
purchase price or construction cost and subsequent reinvestment).
(2) If you or your affiliate purchased the transportation system at
arm's length before June 1, 2000, you must incorporate depreciation on
the schedule based on your purchase price (and subsequent reinvestment)
into your transportation allowance calculations for production after
June 1, 2000, beginning at the point on the depreciation schedule
corresponding to that date. You must prorate your depreciation for
calendar year 2000 by claiming part-year depreciation for the period
from June 1, 2000 until December 31, 2000. You may not adjust your
transportation costs for production before June 1, 2000, using the
depreciation schedule based on your purchase price.
(3) If you are the original owner of the transportation system on
June 1, 2000, or if you purchased your transportation system before
March 1, 1988, you must continue to use your existing depreciation
schedule in calculating actual transportation costs for production in
periods after June 1, 2000.
(4) If you or your affiliate purchase a transportation system at
arm's length from the original owner after June 1, 2000, you must base
your depreciation schedule used in calculating actual transportation
costs on your total capital investment in the system (including your
original purchase price and subsequent reinvestment). You must prorate
your depreciation for the year in which you or your affiliate purchased
the system to reflect the portion of that year for which you or your
affiliate own the system.
(5) If you or your affiliate purchase a transportation system at
arm's length after June 1, 2000, from anyone other than the original
owner, you must assume the depreciation schedule of the person from
whom you bought the system. Include in the depreciation schedule any
subsequent reinvestment.
(i)(1) 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
(i)(2) of this section.
(2) The rate of return is 1.3 times the industrial bond yield index
for Standard & Poor's BBB bond rating. Use the monthly average rate
published in ``Standard & Poor's Bond Guide'' for the first month of
the reporting period for which the allowance applies. Calculate the
rate at the beginning of each subsequent transportation allowance
reporting period.
(j)(1) After a transportation system has been depreciated at or
below a value equal to ten percent of your total capital investment,
you may continue to include in the allowance calculation a cost equal
to ten percent of your total capital investment in the transportation
system multiplied by a rate of return under paragraph (i)(2) of this
section.
(2) You may apply this paragraph to a transportation system that
before June 1, 2000, was depreciated at or below a value equal to ten
percent of your total capital investment.
(k) Calculate the deduction for transportation costs based on your
or your affiliate's cost of transporting each product through each
individual transportation system. Where more than one liquid product is
transported, allocate costs consistently and equitably to each of the
liquid products transported. Your allocation must use the same
proportion as the ratio of the volume of each liquid product (excluding
waste products with no value) to the volume of all liquid products
(excluding waste products with no value).
(1) You may not take an allowance for transporting lease production
that is not royalty-bearing.
(2) You may propose to ONRR a cost allocation method on the basis
of the values of the products transported. ONRR will approve the method
if it is consistent with the purposes of the regulations in this
subpart.
(l)(1) Where you transport both gaseous and liquid products through
the same transportation system, you must propose a cost allocation
procedure to ONRR.
(2) You may use your proposed procedure to calculate a
transportation allowance until ONRR accepts or rejects your cost
allocation. If ONRR rejects your cost allocation, you must amend your
form ONRR-2014 for the months that you used the rejected method and pay
any additional royalty and interest due.
(3) You must submit your initial proposal, including all available
data, within 3 months after first claiming the allocated deductions on
form ONRR-2014.
Sec. [thinsp]1206.112 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. [thinsp]1206.103. As
specified in this section, 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 owed 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).
[[Page 36962]]
(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. [thinsp]1206.110 or Sec.
[thinsp]1206.111, 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, 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 owed
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, adjust the value
between the market center and Cushing, Oklahoma, as follows:
(1) If you have arm's-length exchange agreements between the market
center and Cushing under which you exchange to Cushing at least 20
percent of all the oil you own at the market center during the
production month, you must use the volume-weighted average of the
location and quality differentials from those agreements as the
adjustment between the market center and Cushing for all the oil that
you produce from the leases during that production month for which that
market center is used.
(2) If paragraph (b)(1) of this section does not apply, you must
use the WTI differential published in an ONRR-approved publication for
the market center nearest your lease, for crude oil most similar in
quality to your production, as the adjustment between the market center
and Cushing. (For example, for light sweet crude oil produced offshore
of Louisiana, 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 2 years, unless the publication you use is no longer
published or ONRR revokes its approval of the publication. If you are
required to change publications, you must begin a new 2-year period.
(3) If neither paragraph (b)(1) nor (b)(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 owed 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, also
adjust the NYMEX price or ANS spot price for quality based on premiums
or penalties determined by pipeline quality bank specifications at
intermediate commingling points or at the market center if those points
are downstream of the royalty measurement point approved by BSEE or
BLM, as applicable. 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, unless ONRR approves a higher adjustment.
(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 the lessee refines the oil received in
exchange at Midland. Assume that the NYMEX price is $30.00/bbl,
adjusted for the roll; that the WTI differential (Cushing to Midland)
is -$.10/bbl; that the lessee's exchange agreement between Roswell and
Midland results in a location and quality differential of -$.08/bbl;
and that the lessee's actual cost of transporting the oil from Artesia
to Roswell is $.40/bbl. In this example, the royalty value of the oil
is $30.00-$.10-$.08--$.40 = $29.42/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 $29.42/bbl, as explained in the previous example. In this example,
the other 60 percent also would be valued at $29.42/bbl.
(3) Example. Assume that a Federal lessee produces crude oil from a
lease near Bakersfield, California. Further, assume that the lessee
transports the oil to Hynes Station, and then exchanges the oil to
Cushing which it further exchanges with oil it refines. Assume that the
ANS spot price is $20.00/bbl, and that the lessee's actual cost of
transporting the oil from Bakersfield to Hynes Station is $.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 $.72, including the sulfur and gravity bank
adjustments, and that ONRR approves the lessee's request. In this
example, the preliminary (because the location and quality adjustment
is subject to ONRR review) royalty value of the oil is
[[Page 36963]]
$20.00-$.72-$.28 = $19.00/bbl. The fact that oil was exchanged to
Cushing does not change use of ANS spot prices for royalty valuation.
Sec. [thinsp]1206.113 How will ONRR identify market centers?
ONRR periodically will publish in the Federal Register a list of
market centers. ONRR will monitor market activity and, if necessary,
add to or modify the list of market centers and will publish such
modifications in the Federal Register. ONRR will consider the following
factors and conditions in specifying market centers:
(a) Points where ONRR-approved publications publish prices useful
for index purposes;
(b) Markets served;
(c) Input from industry and others knowledgeable in crude oil
marketing and transportation;
(d) Simplification; and
(e) Other relevant matters.
Sec. [thinsp]1206.114 What are my reporting requirements under an
arm's-length transportation contract?
You or your affiliate must use a separate entry on form ONRR-2014
to notify ONRR of an allowance based on transportation costs you or
your affiliate incur. ONRR may require you or your affiliate to submit
arm's-length transportation contracts, production agreements, operating
agreements, and related documents. Recordkeeping requirements are found
at part 1207 of this chapter.
Sec. [thinsp]1206.115 What are my reporting requirements under a non-
arm's-length transportation arrangement?
(a) You or your affiliate must use a separate entry on form ONRR-
2014 to notify ONRR of an allowance based on transportation costs you
or your affiliate incur.
(b) For new transportation facilities or arrangements, base your
initial deduction on estimates of allowable oil transportation costs
for the applicable period. Use the most recently available operations
data for the transportation system or, if such data are not available,
use estimates based on data for similar transportation systems. Section
1206.117 will apply 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. Recordkeeping requirements are
found at part 1207 of this chapter.
Sec. [thinsp]1206.116 What interest applies if I improperly report a
transportation allowance?
(a) If you or your affiliate deducts a transportation allowance on
form ONRR-2014 that exceeds 50 percent of the value of the oil
transported without obtaining ONRR's prior approval under Sec.
[thinsp]1206.109, you must pay interest on the excess allowance amount
taken from the date that amount is taken to the date you or your
affiliate files an exception request that ONRR approves. If you do not
file an exception request, or if ONRR does not approve your request,
you must pay interest on the excess allowance amount taken from the
date that amount is taken until the date you pay the additional
royalties owed.
(b) If you or your affiliate takes a deduction for transportation
on form ONRR-2014 by improperly netting an allowance against the oil
instead of reporting the allowance as a separate entry, ONRR may assess
a civil penalty under 30 CFR part 1241.
Sec. [thinsp]1206.117 What reporting adjustments must I make for
transportation allowances?
(a) If your or your affiliate's actual transportation allowance is
less than the amount you claimed on form ONRR-2014 for each month
during the allowance reporting period, you must pay additional
royalties plus interest computed under Sec. [thinsp]1218.54 of this
chapter from the date you took the deduction to the date you repay the
difference.
(b) If the actual transportation allowance is greater than the
amount you claimed on form ONRR-2014 for any month during the allowance
form reporting period, you are entitled to a credit plus interest under
applicable rules.
Sec. [thinsp]1206.119 How are royalty quantity and quality
determined?
(a) Compute royalties based on the quantity and quality of oil as
measured at the point of settlement approved by BLM for onshore leases
or BSEE for offshore leases.
(b) If the value of oil determined under this subpart is based upon
a quantity or quality different from the quantity or quality at the
point of royalty settlement approved by the BLM for onshore leases or
BSEE for offshore leases, adjust the value for those differences in
quantity or quality.
(c) Any actual loss that you may incur before the royalty
settlement metering or measurement point is not subject to royalty if
BLM or BSEE, as appropriate, determines that the loss is unavoidable.
(d) Except as provided in paragraph (b) of this section, royalties
are due 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 are claimed to have taken
place either before or after the approved point of royalty settlement.
Sec. [thinsp]1206.120 How are operating allowances determined?
BOEM may use an operating allowance for the purpose of computing
payment obligations when specified in the notice of sale and the lease.
BOEM will specify the allowance amount or formula in the notice of sale
and in the lease agreement.
0
7. Revise subpart D to read as follows:
Subpart D--Federal Gas
Sec.
1206.150 Purpose and scope.
1206.151 Definitions.
1206.152 Valuation standards--unprocessed gas.
1206.153 Valuation standards--processed gas.
1206.154 Determination of quantities and qualities for computing
royalties.
1206.155 Accounting for comparison.
1206.156 Transportation allowances--general.
1206.157 Determination of transportation allowances.
1206.158 Processing allowances--general.
1206.159 Determination of processing allowances.
1206.160 Operating allowances.
Subpart D--Federal Gas
Sec. [thinsp]1206.150 Purpose and scope.
(a) This subpart is applicable to all gas production from Federal
oil and gas leases. The purpose of this subpart is to establish the
value of production for royalty purposes consistent with the mineral
leasing laws, other applicable laws and lease terms.
(b) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee
resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the ONRR Director
establishing a method to determine the value of production from any
lease that ONRR expects at least would approximate the value
established under this subpart; or
(4) An express provision of an oil and gas lease subject to this
subpart; then the statute, settlement agreement, written agreement, or
lease provision will govern to the extent of the inconsistency.
(c) All royalty payments made to ONRR are subject to audit and
adjustment.
(d) The regulations in this subpart are intended to ensure that the
[[Page 36964]]
administration of oil and gas leases is discharged in accordance with
the requirements of the governing mineral leasing laws and lease terms.
Sec. [thinsp]1206.151 Definitions.
For purposes of this subpart:
Affiliate means a person who controls, is controlled by, or is
under common control with another person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the
voting securities, or instruments of ownership, or other forms of
ownership, of another person constitutes control. Ownership of less
than 10 percent constitutes a presumption of noncontrol that ONRR may
rebut.
(2) If there is ownership or common ownership of 10 through 50
percent of the voting securities or instruments of ownership, or other
forms of ownership, of another person, ONRR will consider the following
factors in determining whether 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,
whether a person is the greatest single owner, or whether there is an
opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, pipeline, or other facility;
(iv) The extent of participation by other owners in operations and
day-to-day management of a lease, plant, pipeline, or other facility;
and
(v) Other evidence of power to exercise control over or common
control with another person.
(3) Regardless of any percentage of ownership or common ownership,
relatives, either by blood or marriage, are affiliates.
Allowance means a deduction in determining value for royalty
purposes. Processing allowance means an allowance for the reasonable,
actual costs of processing gas determined under this subpart.
Transportation allowance means an allowance for the reasonable, actual
costs of moving unprocessed gas, residue gas, or gas plant products to
a point of sale or delivery off the lease, unit area, or communitized
area, or away from a processing plant. The transportation allowance
does not include gathering costs.
Area means a geographic region at least as large as the defined
limits of an oil and/or gas field, in which oil and/or gas lease
products have similar quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement between
independent persons who are not affiliates and who have opposing
economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this
definition for that month, as well as when the contract was executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty payment
compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Federal leases.
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.
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 resorting to
processing. Condensate is the mixture of liquid hydrocarbons that
results from condensation of petroleum hydrocarbons existing initially
in a gaseous phase in an underground reservoir.
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by
law that with due consideration creates an obligation.
Field means a geographic region situated over one or more
subsurface oil and gas reservoirs encompassing at least the outermost
boundaries of all oil and gas accumulations known to be within those
reservoirs vertically projected to the land surface. Onshore fields are
usually given names and their official boundaries are often designated
by oil and gas regulatory agencies in the respective States in which
the fields are located. Outer Continental Shelf (OCS) fields are named
and their boundaries are designated by BOEM.
Gas means any fluid, either combustible or noncombustible,
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and
which has neither independent shape nor volume, but tends to expand
indefinitely. It is a substance that exists in a gaseous or rarefied
state under standard temperature and pressure conditions.
Gas plant products means separate marketable elements, compounds,
or mixtures, whether in liquid, gaseous, or solid form, resulting from
processing gas, excluding residue gas.
Gathering means the movement of lease production to a central
accumulation and/or treatment point on the lease, unit or communitized
area, or to a central accumulation or treatment point off the lease,
unit or communitized area as approved by BLM or BSEE OCS operations
personnel for onshore and OCS leases, respectively.
Gross proceeds (for royalty payment purposes) means the total
monies and other consideration accruing to an oil and gas lessee for
the disposition of the gas, residue gas, and gas plant products
produced. Gross proceeds includes, but is not limited to, payments to
the lessee for certain services such as dehydration, measurement, and/
or gathering to the extent that the lessee is obligated to perform them
at no cost to the Federal Government. Tax reimbursements are part of
the gross proceeds accruing to a lessee even though the Federal royalty
interest may be exempt from taxation. Monies and other consideration,
including the forms of consideration identified in this paragraph, to
which a lessee is contractually or legally entitled but which it does
not seek to collect through reasonable efforts are also part of gross
proceeds.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States under a
mineral leasing law that authorizes exploration for, development or
extraction of, or removal of lease products--or the land area covered
by that authorization, whichever is required by the context.
Lease products means any leased minerals attributable to,
originating from, or allocated to Outer Continental Shelf or onshore
Federal leases.
Lessee means any person to whom the United States issues a lease,
and any person who has been assigned an obligation to make royalty or
other payments required by the lease. This includes any person who has
an interest in a lease as well as an operator or payor who has no
interest in the lease but who has assumed the royalty payment
responsibility.
Like-quality lease products means lease products which have similar
chemical, physical, and legal characteristics.
[[Page 36965]]
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.
Marketing affiliate means an affiliate of the lessee whose function
is to acquire only the lessee's production and to market that
production.
Minimum royalty means that minimum amount of annual royalty that
the lessee must pay as specified in the lease or in applicable leasing
regulations.
Net-back method (or work-back method) means a method for
calculating market value of gas at the lease. Under this method, costs
of transportation, processing, or manufacturing are deducted from the
proceeds received for the gas, residue gas or gas plant products, and
any extracted, processed, or manufactured products, or from the value
of the gas, residue gas or gas plant products, and any extracted,
processed, or manufactured products, at the first point at which
reasonable values for any such products may be determined by a sale
pursuant to an arm's-length contract or comparison to other sales of
such products, to ascertain value at the lease.
Net output means the quantity of residue gas and each gas plant
product that a processing plant produces.
Net profit share (for applicable Federal leases) means the
specified share of the net profit from production of oil and gas as
provided in the agreement.
Netting means the deduction of an allowance from the sales value by
reporting a net sales value, instead of correctly reporting the
deduction as a separate entry on form ONRR-2014.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of land 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.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Posted price means the price, net of all adjustments for quality
and location, specified in publicly available price bulletins or other
price notices available as part of normal business operations for
quantities of unprocessed gas, residue gas, or gas plant products in
marketable condition.
Processing means any process designed to remove elements or
compounds (hydrocarbon and nonhydrocarbon) from gas, including
absorption, adsorption, or refrigeration. Field processes which
normally take place on or near the lease, such as natural pressure
reduction, mechanical separation, heating, cooling, dehydration, and
compression, are not considered processing. The changing of pressures
and/or temperatures in a reservoir is not considered processing.
Residue gas means that hydrocarbon gas consisting principally of
methane resulting from processing gas.
Sales type code means the contract type or general disposition
(e.g., arm's-length or non-arm's-length) of production from the lease.
The sales type code applies to the sales contract, or other
disposition, and not to the arm's-length or non-arm's-length nature of
a transportation or processing allowance.
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.
Spot sales agreement means a contract wherein a seller agrees to
sell to a buyer a specified amount of unprocessed gas, residue gas, or
gas plant products at a specified price over a fixed period, usually of
short duration, which does not normally require a cancellation notice
to terminate, and which does not contain an obligation, nor imply an
intent, to continue in subsequent periods.
Warranty contract means a long-term contract entered into prior to
1970, including any amendments thereto, for the sale of gas wherein the
producer agrees to sell a specific amount of gas and the gas delivered
in satisfaction of this obligation may come from fields or sources
outside of the designated fields.
Sec. [thinsp]1206.152 Valuation standards--unprocessed gas.
(a)(1) This section applies to the valuation of all gas that is not
processed and all gas that is processed but is sold or otherwise
disposed of by the lessee pursuant to an arm's-length contract prior to
processing (including all gas where the lessee's arm's-length contract
for the sale of that gas prior to processing provides for the value to
be determined on the basis of a percentage of the purchaser's proceeds
resulting from processing the gas). This section also applies to
processed gas that must be valued prior to processing in accordance
with Sec. [thinsp]1206.155 of this part. Where the lessee's contract
includes a reservation of the right to process the gas and the lessee
exercises that right, Sec. [thinsp]1206.153 of this part shall apply
instead of this section.
(2) The value of production, for royalty purposes, of gas subject
to this subpart shall be the value of gas determined under this section
less applicable allowances.
(b)(1)(i) The value of gas sold under an arm's-length contract is
the gross proceeds accruing to the lessee except as provided in
paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee
shall have the burden of demonstrating that its contract is arm's-
length. The value which the lessee reports, for royalty purposes, is
subject to monitoring, review, and audit. For purposes of this section,
gas which is sold or otherwise transferred to the lessee's marketing
affiliate and then sold by the marketing affiliate pursuant to an
arm's-length contract shall be valued in accordance with this paragraph
based upon the sale by the marketing affiliate. Also, where the
lessee's arm's-length contract for the sale of gas prior to processing
provides for the value to be determined based upon a percentage of the
purchaser's proceeds resulting from processing the gas, the value of
production, for royalty purposes, shall never be less than a value
equivalent to 100 percent of the value of the residue gas attributable
to the processing of the lessee's gas.
(ii) In conducting reviews and audits, ONRR will examine whether
the contract reflects the total consideration actually transferred
either directly or indirectly from the buyer to the seller for the gas.
If the contract does not reflect the total consideration, then the ONRR
may require that the gas sold pursuant to that contract be valued in
accordance with paragraph (c) of this section. Value may not be less
than the gross proceeds accruing to the lessee, including the
additional consideration.
(iii) If the ONRR determines that the gross proceeds accruing to
the lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the production because of misconduct by or between
the contracting parties, or because the lessee otherwise has breached
its duty to the lessor to market the production for the mutual benefit
of the lessee and the lessor, then ONRR shall require that the gas
production be valued pursuant to paragraph (c)(2) or (c)(3) of this
section, and in accordance with the notification requirements of
paragraph (e) of this section. When ONRR determines that the value may
be unreasonable, ONRR will notify the lessee and give the lessee an
opportunity to provide written information justifying the lessee's
value.
(iv) How to value over-delivered volumes under a cash-out program:
This paragraph applies to situations where a pipeline purchases gas
from a lessee
[[Page 36966]]
according to a cash-out program under a transportation contract. For
all over-delivered volumes, the royalty value is the price the pipeline
is required to pay for volumes within the tolerances for over-delivery
specified in the transportation contract. 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.
However, if ONRR determines that the price specified in the
transportation contract for over-delivered volumes is unreasonably low,
the lessee must value all over-delivered volumes under paragraph (c)(2)
or (3) of this section.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, the value of gas sold pursuant to a warranty contract shall be
determined by ONRR, and due consideration will be given to all
valuation criteria specified in this section. The lessee must request a
value determination in accordance with paragraph (g) of this section
for gas sold pursuant to a warranty contract; provided, however, that
any value determination for a warranty contract in effect on the
effective date of these regulations shall remain in effect until
modified by ONRR.
(3) ONRR may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the gas.
(c) The value of gas subject to this section which is not sold
pursuant to an arm's-length contract shall be the reasonable value
determined in accordance with the first applicable of the following
methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition other than by
an arm's-length contract), provided that those gross proceeds are
equivalent to the gross proceeds derived from, or paid under,
comparable arm's-length contracts for purchases, sales, or other
dispositions of like-quality gas in the same field (or, if necessary to
obtain a reasonable sample, from the same area). In evaluating the
comparability of arm's-length contracts for the purposes of these
regulations, the following factors shall be considered: Price, time of
execution, duration, market or markets served, terms, quality of gas,
volume, and such other factors as may be appropriate to reflect the
value of the gas;
(2) A value determined by consideration of other information
relevant in valuing like-quality gas, including gross proceeds under
arm's-length contracts for like-quality gas in the same field or nearby
fields or areas, posted prices for gas, prices received in arm's-length
spot sales of gas, other reliable public sources of price or market
information, and other information as to the particular lease operation
or the saleability of the gas; or
(3) A net-back method or any other reasonable method to determine
value.
(d)(1) Notwithstanding any other provisions of this section, except
paragraph (h) of this section, if the maximum price permitted by
Federal law at which gas may be sold is less than the value determined
pursuant to this section, then ONRR shall accept such maximum price as
the value. For purposes of this section, price limitations set by any
State or local government shall not be considered as a maximum price
permitted by Federal law.
(2) The limitation prescribed in paragraph (d)(1) of this section
shall not apply to gas sold pursuant to a warranty contract and valued
pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of
this section, the lessee shall retain all data relevant to the
determination of royalty value. Such data shall be subject to review
and audit, and ONRR will direct a lessee to use a different value if it
determines that the reported value is inconsistent with the
requirements of these regulations.
(2) Any Federal lessee will make available upon request to the
authorized ONRR or State representatives, to the Office of the
Inspector General of the Department of the Interior, or other person
authorized to receive such information, arm's-length sales and volume
data for like-quality production sold, purchased or otherwise obtained
by the lessee from the field or area or from nearby fields or areas.
(3) A lessee shall notify ONRR if it has determined value pursuant
to paragraph (c)(2) or (3) of this section. The notification shall be
by letter to the ONRR Director for Office of Natural Resources Revenue
or his/her designee. The letter shall identify the valuation method to
be used and contain a brief description of the procedure to be
followed. The notification required by this paragraph is a one-time
notification due no later than the end of the month following the month
the lessee first reports royalties on a form ONRR-2014 using a
valuation method authorized by paragraph (c)(2) or (3) of this section,
and each time there is a change in a method under paragraph (c)(2) or
(3) of this section.
(f) If ONRR determines that a lessee has not properly determined
value, the lessee shall pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by ONRR. The lessee shall
also pay interest on that difference computed pursuant to Sec.
[thinsp]1218.54 of this chapter. If the lessee is entitled to a credit,
ONRR will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from ONRR. In that
event, the lessee shall propose to ONRR a value determination method,
and may use that method in determining value for royalty purposes until
ONRR issues its decision. The lessee shall submit all available data
relevant to its proposal. The ONRR shall expeditiously determine the
value based upon the lessee's proposal and any additional information
ONRR deems necessary. In making a value determination ONRR may use any
of the valuation criteria authorized by this subpart. That
determination shall remain effective for the period stated therein.
After ONRR issues its determination, the lessee shall make the
adjustments in accordance with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no
circumstances shall the value of production for royalty purposes be
less than the gross proceeds accruing to the lessee for lease
production, less applicable allowances.
(i) The lessee must place gas in marketable condition and market
the gas for the mutual benefit of the lessee and the lessor at no cost
to the Federal Government. Where the value established under this
section is determined by a lessee's gross proceeds, that value will be
increased to the extent that the gross proceeds have been reduced
because the purchaser, or any other person, is providing certain
services the cost of which ordinarily is the responsibility of the
lessee to place the gas in marketable condition or to market the gas.
(j) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. If there
is no contract revision or amendment, and the lessee fails to take
proper or timely action to receive prices or benefits to which it is
entitled, it must pay royalty at a value based upon that obtainable
price or benefit. Contract revisions or amendments shall be in writing
and signed by all parties to an arm's-length contract. If the lessee
makes timely application for a price increase or benefit allowed under
its contract but the purchaser refuses, and the lessee takes reasonable
measures, which are documented, to force purchaser
[[Page 36967]]
compliance, the lessee will owe no additional royalties unless or until
monies or consideration resulting from the price increase or additional
benefits are received. This paragraph shall not be construed to permit
a lessee to avoid its royalty payment obligation in situations where a
purchaser fails to pay, in whole or in part or timely, for a quantity
of gas.
(k) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by ONRR of value under this section
shall be considered final or binding as against the Federal Government
or its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to ONRR to support valuation
proposals, including transportation or extraordinary cost allowances,
is exempted from disclosure by the Freedom of Information Act, 5 U.S.C.
552, or other Federal law. Any data specified by law to be privileged,
confidential, or otherwise exempt will be maintained in a confidential
manner in accordance with applicable law and regulations. All requests
for information about determinations made under this subpart are to be
submitted in accordance with the Freedom of Information Act regulation
of the Department of the Interior, 43 CFR part 2.
Sec. [thinsp]1206.153 Valuation standards--processed gas.
(a)(1) This section applies to the valuation of all gas that is
processed by the lessee and any other gas production to which this
subpart applies and that is not subject to the valuation provisions of
Sec. 1206.152 of this part. This section applies where the lessee's
contract includes a reservation of the right to process the gas and the
lessee exercises that right.
(2) The value of production, for royalty purposes, of gas subject
to this section shall be the combined value of the residue gas and all
gas plant products determined pursuant to this section, plus the value
of any condensate recovered downstream of the point of royalty
settlement without resorting to processing determined pursuant to Sec.
1206.102 of this part, less applicable transportation allowances and
processing allowances determined pursuant to this subpart.
(b)(1)(i) The value of residue gas or any gas plant product sold
under an arm's-length contract is the gross proceeds accruing to the
lessee, except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of
this section. The lessee shall have the burden of demonstrating that
its contract is arm's-length. The value that the lessee reports for
royalty purposes is subject to monitoring, review, and audit. For
purposes of this section, residue gas or any gas plant product which is
sold or otherwise transferred to the lessee's marketing affiliate and
then sold by the marketing affiliate pursuant to an arm's-length
contract shall be valued in accordance with this paragraph based upon
the sale by the marketing affiliate.
(ii) In conducting these reviews and audits, ONRR will examine
whether or not the contract reflects the total consideration actually
transferred either directly or indirectly from the buyer to the seller
for the residue gas or gas plant product. If the contract does not
reflect the total consideration, then the ONRR may require that the
residue gas or gas plant product sold pursuant to that contract be
valued in accordance with paragraph (c) of this section. Value may not
be less than the gross proceeds accruing to the lessee, including the
additional consideration.
(iii) If the ONRR determines that the gross proceeds accruing to
the lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the residue gas or gas plant product because of
misconduct by or between the contracting parties, or because the lessee
otherwise has breached its duty to the lessor to market the production
for the mutual benefit of the lessee and the lessor, then ONRR shall
require that the residue gas or gas plant product be valued pursuant to
paragraph (c)(2) or (3) of this section, and in accordance with the
notification requirements of paragraph (e) of this section. When ONRR
determines that the value may be unreasonable, ONRR will notify the
lessee and give the lessee an opportunity to provide written
information justifying the lessee's value.
(iv) How to value over-delivered volumes under a cash-out program:
This paragraph applies to situations where a pipeline purchases gas
from a lessee according to a cash-out program under a transportation
contract. For all over-delivered volumes, the royalty value is the
price the pipeline is required to pay for volumes within the tolerances
for over-delivery specified in the transportation contract. 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. However, if ONRR determines that the price specified in the
transportation contract for over-delivered volumes is unreasonably low,
the lessee must value all over-delivered volumes under paragraph (c)(2)
or (3) of this section.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, the value of residue gas sold pursuant to a warranty contract
shall be determined by ONRR, and due consideration will be given to all
valuation criteria specified in this section. The lessee must request a
value determination in accordance with paragraph (g) of this section
for gas sold pursuant to a warranty contract; provided, however, that
any value determination for a warranty contract in effect on the
effective date of these regulations shall remain in effect until
modified by ONRR.
(3) ONRR may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the residue gas or gas plant
product.
(c) The value of residue gas or any gas plant product which is not
sold pursuant to an arm's-length contract shall be the reasonable value
determined in accordance with the first applicable of the following
methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition other than by
an arm's-length contract), provided that those gross proceeds are
equivalent to the gross proceeds derived from, or paid under,
comparable arm's-length contracts for purchases, sales, or other
dispositions of like quality residue gas or gas plant products from the
same processing plant (or, if necessary to obtain a reasonable sample,
from nearby plants). In evaluating the comparability of arm's-length
contracts for the purposes of these regulations, the following factors
shall be considered: Price, time of execution, duration, market or
markets served, terms, quality of residue gas or gas plant products,
volume, and such other factors as may be appropriate to reflect the
value of the residue gas or gas plant products;
(2) A value determined by consideration of other information
relevant in valuing like-quality residue gas or gas plant products,
including gross proceeds under arm's-length contracts for like-quality
residue gas or gas plant products from the same gas plant or other
nearby processing plants, posted prices for residue gas or gas plant
products, prices received in spot sales of residue gas or gas plant
products, other reliable public sources of price or market information,
and other information as to the particular lease operation or the
saleability of such residue gas or gas plant products; or
(3) A net-back method or any other reasonable method to determine
value.
[[Page 36968]]
(d)(1) Notwithstanding any other provisions of this section, except
paragraph (h) of this section, if the maximum price permitted by
Federal law at which any residue gas or gas plant products may be sold
is less than the value determined pursuant to this section, then ONRR
shall accept such maximum price as the value. For the purposes of this
section, price limitations set by any State or local government shall
not be considered as a maximum price permitted by Federal law.
(2) The limitation prescribed by paragraph (d)(1) of this section
shall not apply to residue gas sold pursuant to a warranty contract and
valued pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of
this section, the lessee shall retain all data relevant to the
determination of royalty value. Such data shall be subject to review
and audit, and ONRR will direct a lessee to use a different value if it
determines upon review or audit that the reported value is inconsistent
with the requirements of these regulations.
(2) Any Federal lessee will make available upon request to the
authorized ONRR or State representatives, to the Office of the
Inspector General of the Department of the Interior, or other persons
authorized to receive such information, arm's-length sales and volume
data for like-quality residue gas and gas plant products sold,
purchased or otherwise obtained by the lessee from the same processing
plant or from nearby processing plants.
(3) A lessee shall notify ONRR if it has determined any value
pursuant to paragraph (c)(2) or (3) of this section. The notification
shall be by letter to the ONRR Director for Office of Natural Resources
or his/her designee. The letter shall identify the valuation method to
be used and contain a brief description of the procedure to be
followed. The notification required by this paragraph is a one-time
notification due no later than the end of the month following the month
the lessee first reports royalties on a form ONRR-2014 using a
valuation method authorized by paragraph (c)(2) or (3) of this section,
and each time there is a change in a method under paragraph (c)(2) or
(3) of this section.
(f) If ONRR determines that a lessee has not properly determined
value, the lessee shall pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by ONRR. The lessee shall
also pay interest computed on that difference pursuant to Sec.
[thinsp]1218.54 of this chapter. If the lessee is entitled to a credit,
ONRR will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from ONRR. In that
event, the lessee shall propose to ONRR a value determination method,
and may use that method in determining value for royalty purposes until
ONRR issues its decision. The lessee shall submit all available data
relevant to its proposal. The ONRR shall expeditiously determine the
value based upon the lessee's proposal and any additional information
ONRR deems necessary. In making a value determination, ONRR may use any
of the valuation criteria authorized by this subpart. That
determination shall remain effective for the period stated therein.
After ONRR issues its determination, the lessee shall make the
adjustments in accordance with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no
circumstances shall the value of production for royalty purposes be
less than the gross proceeds accruing to the lessee for residue gas
and/or any gas plant products, less applicable transportation
allowances and processing allowances determined pursuant to this
subpart.
(i) The lessee must place residue gas and gas plant products in
marketable condition and market the residue gas and gas plant products
for the mutual benefit of the lessee and the lessor at no cost to the
Federal Government. Where the value established under this section is
determined by a lessee's gross proceeds, that value will be increased
to the extent that the gross proceeds have been reduced because the
purchaser, or any other person, is providing certain services the cost
of which ordinarily is the responsibility of the lessee to place the
residue gas or gas plant products in marketable condition or to market
the residue gas and gas plant products.
(j) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled it
must pay royalty at a value based upon that obtainable price or
benefit. Contract revisions or amendments shall be in writing and
signed by all parties to an arm's-length contract. If the lessee makes
timely application for a price increase or benefit allowed under its
contract but the purchaser refuses, and the lessee takes reasonable
measures, which are documented, to force purchaser compliance, the
lessee will owe no additional royalties unless or until monies or
consideration resulting from the price increase or additional benefits
are received. This paragraph shall not be construed to permit a lessee
to avoid its royalty payment obligation in situations where a purchaser
fails to pay, in whole or in part, or timely, for a quantity of residue
gas or gas plant product.
(k) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by ONRR of value under this section
shall be considered final or binding against the Federal Government or
its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to ONRR to support valuation
proposals, including transportation allowances, processing allowances
or extraordinary cost allowances, is exempted from disclosure by the
Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any
data specified by law to be privileged, confidential, or otherwise
exempt, will be maintained in a confidential manner in accordance with
applicable law and regulations. All requests for information about
determinations made under this part are to be submitted in accordance
with the Freedom of Information Act regulation of the Department of the
Interior, 43 CFR part 2.
Sec. [thinsp]1206.154 Determination of quantities and qualities for
computing royalties.
(a)(1) Royalties shall be computed on the basis of the quantity and
quality of unprocessed gas at the point of royalty settlement approved
by BLM or BSEE for onshore and OCS leases, respectively.
(2) If the value of gas determined pursuant to Sec.
[thinsp]1206.152 of this subpart is based upon a quantity and/or
quality that is different from the quantity and/or quality at the point
of royalty settlement, as approved by BLM or BSEE, that value shall be
adjusted 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 the value of residue gas and/or gas plant products
determined pursuant to Sec. [thinsp]1206.153 of this subpart is based
upon 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 in accordance with paragraph (c) of this section, that value
shall be adjusted for
[[Page 36969]]
the differences in quantity and/or quality.
(c) The quantity of the residue gas and gas plant products
attributable to a lease shall be determined according to the following
procedure:
(1) When the net output of the processing plant is derived from gas
obtained from only one lease, the quantity of the residue gas and gas
plant products on which computations of royalty are based is the net
output of the plant.
(2) When the net output of a processing plant is derived from gas
obtained from more than one lease producing gas of uniform content, the
quantity of the residue gas and gas plant products allocable to each
lease shall be in 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 nonuniform content,
the quantity of the residue gas allocable to each lease will be
determined by multiplying the amount of gas delivered to the plant from
the lease by the residue gas content of the gas, and dividing the
arithmetical product thus obtained 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. The net output of gas
plant products allocable to each lease will be determined by
multiplying the amount of gas delivered to the plant from the lease by
the gas plant product content of the gas, and dividing the arithmetical
product thus obtained 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) A lessee may request ONRR approval of other methods for
determining the quantity of residue gas and gas plant products
allocable to each lease. If approved, such method will be applicable to
all gas production from Federal leases that is processed in the same
plant.
(d)(1) No deductions may be made from the royalty volume or royalty
value for actual or theoretical losses. Any actual loss of unprocessed
gas that may be sustained prior to the royalty settlement metering or
measurement point will not be subject to royalty provided that such
loss is determined to have been unavoidable by BLM or BSEE, as
appropriate.
(2) Except as provided in paragraph (d)(1) of this section and
Sec. [thinsp]1202.151(c), royalties are due on 100 percent of the
volume determined in accordance with paragraphs (a) through (c) of this
section. There can be no reduction in that determined volume for actual
losses after the quantity basis has been determined or for theoretical
losses that are claimed 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.
There can be no deduction from the value of the unprocessed gas,
residue gas, and/or gas plant products to compensate for actual losses
after the quantity basis has been determined, or for theoretical losses
that are claimed to have taken place.
Sec. [thinsp]1206.155 Accounting for comparison.
(a) Except as provided in paragraph (b) of this section, where the
lessee (or a person to whom the lessee has transferred gas pursuant to
a non-arm's-length contract or without a contract) processes the
lessee's gas and after processing the gas the residue gas is not sold
pursuant to an arm's-length contract, the value, for royalty purposes,
shall be the greater of:
(1) The combined value, for royalty purposes, of the residue gas
and gas plant products resulting from processing the gas determined
pursuant to Sec. [thinsp]1206.153 of this subpart, plus the value, for
royalty purposes, of any condensate recovered downstream of the point
of royalty settlement without resorting to processing determined
pursuant to Sec. [thinsp]1206.102 of this subpart; or
(2) The value, for royalty purposes, of the gas prior to processing
determined in accordance with Sec. [thinsp]1206.152 of this subpart.
(b) The requirement for accounting for comparison contained in the
terms of leases will govern as provided in Sec. [thinsp]1206.150(b) of
this subpart. When accounting for comparison is required by the lease
terms, such accounting for comparison shall be determined in accordance
with paragraph (a) of this section.
Sec. [thinsp]1206.156 Transportation allowances--general.
(a) Where the value of gas has been determined pursuant to Sec.
[thinsp]1206.152 or Sec. [thinsp]1206.153 of this subpart at a point
(e.g., sales point or point of value determination) off the lease, ONRR
shall allow a deduction for the reasonable actual costs incurred by the
lessee to transport unprocessed gas, residue gas, and gas plant
products from a lease to a point off the lease including, if
appropriate, transportation from the lease to a gas processing plant
off the lease and from the plant to a point away from the plant.
(b) Transportation costs must be allocated among all products
produced and transported as provided in Sec. [thinsp]1206.157.
(c)(1) Except as provided in paragraph (c)(3) of this section, for
unprocessed gas valued in accordance with Sec. [thinsp]1206.152 of
this subpart, the transportation allowance deduction on the basis of a
sales type code may not exceed 50 percent of the value of the
unprocessed gas determined under Sec. [thinsp]1206.152 of this
subpart.
(2) Except as provided in paragraph (c)(3) of this section, for gas
production valued in accordance with Sec. [thinsp]1206.153 of this
subpart, the transportation allowance deduction on the basis of a sales
type code may not exceed 50 percent of the value of the residue gas or
gas plant product determined under Sec. [thinsp]1206.153 of this
subpart. For purposes of this section, natural gas liquids will be
considered one product.
(3) Upon request of a lessee, ONRR may approve a transportation
allowance deduction in excess of the limitations prescribed by
paragraphs (c)(1) and (2) of this section. The lessee must demonstrate
that the transportation costs incurred in excess of the limitations
prescribed in paragraphs (c)(1) and (2) of this section were
reasonable, actual, and necessary. An application for exception (using
form ONRR-4393, Request to Exceed Regulatory Allowance Limitation) must
contain all relevant and supporting documentation necessary for ONRR to
make a determination. Under no circumstances may the value for royalty
purposes under any sales type code be reduced to zero.
(d) If, after a review or audit, ONRR determines that a lessee has
improperly determined a transportation allowance authorized by this
subpart, then the lessee must pay any additional royalties, plus
interest, determined in accordance with Sec. [thinsp]1218.54 of this
chapter, or will be entitled to a credit, with interest. If the lessee
takes a deduction for transportation on form ONRR-2014 by improperly
netting the allowance against the sales value of the unprocessed gas,
residue gas, and gas plant products instead of reporting the allowance
as a separate entry, ONRR may assess a civil penalty under 30 CFR part
1241.
[[Page 36970]]
Sec. [thinsp]1206.157 Determination of transportation allowances.
(a) Arm's-length transportation contracts. (1)(i) For
transportation costs incurred by a lessee under an arm's-length
contract, the transportation allowance shall be the reasonable, actual
costs incurred by the lessee for transporting the unprocessed gas,
residue gas and/or gas plant products under that contract, except as
provided in paragraphs (a)(1)(ii) and (iii) of this section, subject to
monitoring, review, audit, and adjustment. The lessee shall have the
burden of demonstrating that its contract is arm's-length. ONRR's prior
approval is not required before a lessee may deduct costs incurred
under an arm's-length contract. Such allowances shall be subject to the
provisions of paragraph (f) of this section. The lessee must claim a
transportation allowance by reporting it as a separate entry on the
form ONRR-2014.
(ii) In conducting reviews and audits, ONRR will examine whether or
not the contract reflects more than the consideration actually
transferred either directly or indirectly from the lessee to the
transporter for the transportation. If the contract reflects more than
the total consideration, then the ONRR may require that the
transportation allowance be determined in accordance with paragraph (b)
of this section.
(iii) If the ONRR determines that the consideration paid pursuant
to an arm's-length transportation contract does not reflect the
reasonable value of the transportation because of misconduct by or
between the contracting parties, or because the lessee otherwise has
breached its duty to the lessor to market the production for the mutual
benefit of the lessee and the lessor, then ONRR shall require that the
transportation allowance be determined in accordance with paragraph (b)
of this section. When ONRR determines that the value of the
transportation may be unreasonable, ONRR will notify the lessee and
give the lessee an opportunity to provide written information
justifying the lessee's transportation costs.
(2)(i) If an arm's-length transportation contract includes more
than one product in a gaseous phase and the transportation costs
attributable to each product cannot be determined from the contract,
the total transportation costs shall be allocated in a consistent and
equitable manner to each of the products transported in the same
proportion as the ratio of the volume of each product (excluding waste
products which have no value) to the volume of all products in the
gaseous phase (excluding waste products which have no value). Except as
provided in this paragraph, no allowance may be taken for the costs of
transporting lease production which is not royalty bearing without ONRR
approval.
(ii) Notwithstanding the requirements of paragraph (a)(2)(i) of
this section, the lessee may propose to ONRR a cost allocation method
on the basis of the values of the products transported. ONRR shall
approve the method unless it determines that it is not consistent with
the purposes of the regulations in this part.
(3) If an arm's-length transportation contract includes both
gaseous and liquid products and the transportation costs attributable
to each cannot be determined from the contract, the lessee shall
propose an allocation procedure to ONRR. The lessee may use the
transportation allowance determined in accordance with its proposed
allocation procedure until ONRR issues its determination on the
acceptability of the cost allocation. The lessee shall submit all
relevant data to support its proposal. ONRR shall then determine the
gas transportation allowance based upon the lessee's proposal and any
additional information ONRR deems necessary. The lessee must submit the
allocation proposal within 3 months of claiming the allocated deduction
on the form ONRR-2014.
(4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar per unit, the lessee shall
convert whatever consideration is paid to a dollar value equivalent for
the purposes of this section.
(5) Where an arm's-length sales contract price or a posted price
includes a provision whereby the listed price is reduced by a
transportation factor, ONRR will not consider the transportation factor
to be a transportation allowance. The transportation factor may be used
in determining the lessee's gross proceeds for the sale of the product.
The transportation factor may not exceed 50 percent of the base price
of the product without ONRR approval.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length transportation contract or has no contract, including
those situations where the lessee performs transportation services for
itself, the transportation allowance will be based upon the lessee's
reasonable actual costs as provided in this paragraph. All
transportation allowances deducted under a non-arm's-length or no
contract situation are subject to monitoring, review, audit, and
adjustment. The lessee must claim a transportation allowance by
reporting it as a separate entry on the form ONRR-2014. When necessary
or appropriate, ONRR may direct a lessee to modify its estimated or
actual transportation allowance deduction.
(2) The transportation allowance for non-arm's-length or no-
contract situations shall be based upon the lessee's actual costs for
transportation during the reporting period, including operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the initial
depreciable investment in the transportation system multiplied by a
rate of return in accordance with paragraph (b)(2)(iv)(B) of this
section. Allowable capital costs are generally those costs for
depreciable fixed assets (including costs of delivery and installation
of capital equipment) which are an integral part of the transportation
system.
(i) Allowable operating expenses include: Operations supervision
and engineering; operations labor; fuel; utilities; materials; ad
valorem property taxes; rent; supplies; and any other directly
allocable and attributable operating expense which the lessee can
document.
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which
the lessee can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on
depreciable capital investment. After a lessee has elected to use
either method for a transportation system, the lessee may not later
elect to change to the other alternative without approval of the ONRR.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services, or a
unit of production method. After an election is made, the lessee may
not change methods without ONRR approval. A change in ownership of a
transportation system shall not alter the depreciation schedule
established by the original transporter/lessee for purposes of the
allowance calculation.
[[Page 36971]]
With or without a change in ownership, a transportation system shall be
depreciated only once. Equipment shall not be depreciated below a
reasonable salvage value.
(B) The ONRR shall allow as a cost an amount equal to the allowable
initial capital investment in the transportation system multiplied by
the rate of return determined pursuant to paragraph (b)(2)(v) of this
section. No allowance shall be provided for depreciation. This
alternative shall apply only to transportation facilities first placed
in service after March 1, 1988.
(v) The rate of return must be 1.3 times the industrial rate
associated with Standard & Poor's BBB rating. The BBB rate must be the
monthly average rate as published in Standard & Poor's Bond Guide for
the first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3)(i) The deduction for transportation costs shall be determined
on the basis of the lessee's cost of transporting each product through
each individual transportation system. Where more than one product in a
gaseous phase is transported, the allocation of costs to each of the
products transported shall be made in a consistent and equitable manner
in the same proportion as the ratio of the volume of each product
(excluding waste products which have no value) to the volume of all
products in the gaseous phase (excluding waste products which have no
value). Except as provided in this paragraph, the lessee may not take
an allowance for transporting a product which is not royalty bearing
without ONRR approval.
(ii) Notwithstanding the requirements of paragraph (b)(3)(i) of
this section, the lessee may propose to the ONRR a cost allocation
method on the basis of the values of the products transported. ONRR
shall approve the method unless it determines that it is not consistent
with the purposes of the regulations in this part.
(4) Where both gaseous and liquid products are transported through
the same transportation system, the lessee shall propose a cost
allocation procedure to ONRR. The lessee may use the transportation
allowance determined in accordance with its proposed allocation
procedure until ONRR issues its determination on the acceptability of
the cost allocation. The lessee shall submit all relevant data to
support its proposal. ONRR shall then determine the transportation
allowance based upon the lessee's proposal and any additional
information ONRR deems necessary. The lessee must submit the allocation
proposal within 3 months of claiming the allocated deduction on the
form ONRR-2014.
(5) You may apply for an exception from the requirement to compute
actual costs under paragraphs (b)(1) through (4) of this section.
(i) ONRR will grant the exception if:
(A) The transportation system has a tariff filed with the Federal
Energy Regulatory Commission (FERC) or a State regulatory agency, that
FERC or the State regulatory agency has permitted to become effective,
and
(B) Third parties are paying prices, including discounted prices,
under the tariff to transport gas on the system under arm's-length
transportation contracts.
(ii) If ONRR approves the exception, you must calculate your
transportation allowance for each production month based on the lesser
of the volume-weighted average of the rates paid by the third parties
under arm's-length transportation contracts during that production
month or the non-arm's-length payment by the lessee to the pipeline.
(iii) If during any production month there are no prices paid under
the tariff by third parties to transport gas on the system under arm's-
length transportation contracts, you may use the volume-weighted
average of the rates paid by third parties under arm's-length
transportation contracts in the most recent preceding production month
in which the tariff remains in effect and third parties paid such
rates, for up to five successive production months. You must use the
non-arm's-length payment by the lessee to the pipeline if it is less
than the volume-weighted average of the rates paid by third parties
under arm's-length contracts.
(c) Reporting requirements--(1) Arm's-length contracts. (i) You
must use a separate entry on form ONRR-2014 to notify ONRR of a
transportation allowance.
(ii) ONRR may require you to submit arm's-length transportation
contracts, production agreements, operating agreements, and related
documents. Recordkeeping requirements are found at part 1207 of this
chapter.
(iii) You may not use a transportation allowance that was in effect
before March 1, 1988. You must use the provisions of this subpart to
determine your transportation allowance.
(2) Non-arm's-length or no contract. (i) You must use a separate
entry on form ONRR-2014 to notify ONRR of a transportation allowance.
(ii) For new transportation facilities or arrangements, base your
initial deduction on estimates of allowable gas transportation costs
for the applicable period. Use the most recently available operations
data for the transportation system or, if such data are not available,
use estimates based on data for similar transportation systems.
Paragraph (e) of this section will apply when you amend your report
based on your actual costs.
(iii) ONRR may require you to submit all data used to calculate the
allowance deduction. Recordkeeping requirements are found at part 1207
of this chapter.
(iv) If you are authorized under paragraph (b)(5) of this section
to use an exception to the requirement to calculate your actual
transportation costs, you must follow the reporting requirements of
paragraph (c)(1) of this section.
(v) You may not use a transportation allowance that was in effect
before March 1, 1988. You must use the provisions of this subpart to
determine your transportation allowance.
(d) Interest and assessments. (1) If a lessee deducts a
transportation allowance on its form ONRR-2014 that exceeds 50 percent
of the value of the gas transported without obtaining prior approval of
ONRR under Sec. 1206.156, the lessee shall pay interest on the excess
allowance amount taken from the date such amount is taken to the date
the lessee files an exception request with ONRR.
(2) If a lessee erroneously reports a transportation allowance
which results in an underpayment of royalties, interest shall be paid
on the amount of that underpayment.
(3) Interest required to be paid by this section shall be
determined in accordance with Sec. 1218.54 of this chapter.
(e) Adjustments. (1) If the actual transportation allowance is less
than the amount the lessee has taken on form ONRR-2014 for each month
during the allowance reporting period, the lessee shall be required to
pay additional royalties due plus interest computed under Sec. 1218.54
of this chapter from the allowance reporting period when the lessee
took the deduction to the date the lessee repays the difference to
ONRR. If the actual transportation allowance is greater than the amount
the lessee has taken on form ONRR-2014 for each month during the
allowance reporting period, the lessee shall be entitled to a credit
without interest.
(2) For lessees transporting production from onshore Federal
leases, the lessee must submit a corrected form ONRR-2014 to reflect
actual costs, together with any payment, in accordance with
instructions provided by ONRR.
[[Page 36972]]
(3) For lessees transporting gas production from leases on the OCS,
if the lessee's estimated transportation allowance exceeds the
allowance based on actual costs, the lessee must submit a corrected
form ONRR-2014 to reflect actual costs, together with its payment, in
accordance with instructions provided by ONRR. If the lessee's
estimated transportation allowance is less than the allowance based on
actual costs, the refund procedure will be specified by ONRR.
(f) Allowable costs in determining transportation allowances. You
may include, but are not limited to (subject to the requirements of
paragraph (g) of this section), the following costs in determining the
arm's-length transportation allowance under paragraph (a) of this
section or the non-arm's-length transportation allowance under
paragraph (b) 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
paragraph.
(1) Firm demand charges paid to pipelines. You may deduct firm
demand charges or capacity reservation fees paid to a pipeline,
including charges or fees for unused firm capacity that you have not
sold before you report your allowance. If you receive 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 receive a payment or credit from the pipeline for
penalty refunds, rate case refunds, or other reasons, you must reduce
the firm demand charge claimed on the form ONRR-2014 by the amount of
that payment. You must modify the form ONRR-2014 by the amount received
or credited for the affected reporting period, and pay any resulting
royalty and late payment interest due;
(2) Gas supply realignment (GSR) costs. The GSR costs result from a
pipeline reforming or terminating supply contracts with producers to
implement the restructuring requirements of FERC Orders in 18 CFR part
284;
(3) Commodity charges. The commodity charge allows the pipeline to
recover the costs of providing service;
(4) Wheeling costs. Hub operators charge a wheeling cost for
transporting gas from one pipeline to either the same or another
pipeline through a market center or hub. A hub is a connected manifold
of pipelines through which a series of incoming pipelines are
interconnected to a series of outgoing pipelines;
(5) Gas Research Institute (GRI) fees. The GRI conducts research,
development, and commercialization programs on natural gas related
topics for the benefit of the U.S. gas industry and gas customers. GRI
fees are allowable provided such fees are mandatory in FERC-approved
tariffs;
(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to
pipelines to pay for its operating expenses;
(7) Payments (either volumetric or in value) for actual or
theoretical losses. However, theoretical losses are not deductible in
non-arm's-length transportation arrangements unless the transportation
allowance is based on arm's-length transportation rates charged under a
FERC- or State regulatory-approved tariff under paragraph (b)(5) of
this section. If you receive volumes or credit for line gain, you must
reduce your transportation allowance accordingly and pay any resulting
royalties and late payment interest due;
(8) Temporary storage services. This includes short duration
storage services offered by market centers or hubs (commonly referred
to as ``parking'' or ``banking''), or other temporary storage services
provided by pipeline transporters, whether actual or provided as a
matter of accounting. Temporary storage is limited to 30 days or less;
and
(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. Sec. 1206.152(i) and
1206.153(i) of this part.
(10) Costs of surety. You may deduct the costs of securing a letter
of credit, or other surety, that the pipeline requires you as a shipper
to maintain under an arm's-length transportation contract.
(g) Nonallowable costs in determining transportation allowances.
Lessees may not include the following costs in determining the arm's-
length transportation allowance under paragraph (a) of this section or
the non-arm's-length transportation allowance under paragraph (b) of
this section:
(1) Fees or costs incurred for storage. This includes storing
production in a storage facility, whether on or off the lease, for more
than 30 days;
(2) Aggregator/marketer fees. This includes fees you pay to another
person (including your affiliates) to market your gas, including
purchasing and reselling the gas, or finding or maintaining a market
for the gas production;
(3) Penalties you incur as shipper. These penalties include, but
are not limited to:
(i) Over-delivery cash-out penalties. This includes the difference
between the price the pipeline pays you for over-delivered volumes
outside the tolerances and the price you receive for over-delivered
volumes within the tolerances;
(ii) Scheduling penalties. This includes penalties you incur for
differences between daily volumes delivered into the pipeline and
volumes scheduled or nominated at a receipt or delivery point;
(iii) Imbalance penalties. This includes penalties you incur
(generally on a monthly basis) for differences between volumes
delivered into the pipeline and volumes scheduled or nominated at a
receipt or delivery point; and
(iv) Operational penalties. This includes fees you incur for
violation of the pipeline's curtailment or operational orders issued to
protect the operational integrity of the pipeline;
(4) Intra-hub transfer fees. These are fees you pay to hub
operators for administrative services (e.g., title transfer tracking)
necessary to account for the sale of gas within a hub;
(5) Fees paid to brokers. This includes fees paid 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
paid to parties who provide scheduling services, if such fees are
separately identified from aggregator/marketer fees;
(7) Internal costs. This includes salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to
schedule, nominate, and account for sale or movement of production; and
(8) Other nonallowable costs. Any cost you incur for services you
are required to provide at no cost to the lessor.
(h) Other transportation cost determinations. Use this section when
calculating transportation costs to establish value using a netback
procedure or any other procedure that requires deduction of
transportation costs.
Sec. [thinsp]1206.158 Processing allowances--general.
(a) Where the value of gas is determined pursuant to Sec.
[thinsp]1206.153 of this subpart, a deduction shall be allowed for the
reasonable actual costs of processing.
(b) Processing costs must be allocated among the gas plant
products. A separate processing allowance must be determined for each
gas plant product
[[Page 36973]]
and processing plant relationship. Natural gas liquids (NGL's) shall be
considered as one product.
(c)(1) Except as provided in paragraph (d)(2) of this section, the
processing allowance shall not be applied against the value of the
residue gas. Where there is no residue gas ONRR may designate an
appropriate gas plant product against which no allowance may be
applied.
(2) Except as provided in paragraph (c)(3) of this section, the
processing allowance deduction on the basis of an individual product
shall not exceed 66 \2/3\ percent of the value of each gas plant
product determined in accordance with Sec. [thinsp]1206.153 of this
subpart (such value to be reduced first for any transportation
allowances related to postprocessing transportation authorized by Sec.
[thinsp]1206.156 of this subpart).
(3) Upon request of a lessee, ONRR may approve a processing
allowance in excess of the limitation prescribed by paragraph (c)(2) of
this section. The lessee must demonstrate that the processing costs
incurred in excess of the limitation prescribed in paragraph (c)(2) of
this section were reasonable, actual, and necessary. An application for
exception (using form ONRR-4393, Request to Exceed Regulatory Allowance
Limitation) shall contain all relevant and supporting documentation for
ONRR to make a determination. Under no circumstances shall the value
for royalty purposes of any gas plant product be reduced to zero.
(d)(1) Except as provided in paragraph (d)(2) of this section, no
processing cost deduction shall be allowed 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. Where gas is
processed for the removal of acid gases, commonly referred to as
``sweetening,'' no processing cost deduction shall be allowed for such
costs unless the acid gases removed are further processed into a gas
plant product. In such event, the lessee shall be eligible for a
processing allowance as determined in accordance with this subpart.
However, ONRR will not grant any processing allowance for processing
lease production which is not royalty bearing.
(2)(i) If the lessee incurs extraordinary costs for processing gas
production from a gas production operation, it may apply to ONRR for an
allowance for those costs which shall be in addition to any other
processing allowance to which the lessee is entitled pursuant to this
section. Such an allowance may be granted only if the lessee can
demonstrate that the costs are, by reference to standard industry
conditions and practice, extraordinary, unusual, or unconventional.
(ii) Prior ONRR approval to continue an extraordinary processing
cost allowance is not required. However, to retain the authority to
deduct the allowance the lessee must report the deduction to ONRR in a
form and manner prescribed by ONRR.
(e) If ONRR determines that a lessee has improperly determined a
processing allowance authorized by this subpart, then the lessee must
pay any additional royalties, plus interest determined under Sec.
[thinsp]1218.54 of this chapter, or will be entitled to a credit with
interest. If the lessee takes a deduction for processing on form ONRR-
2014 by improperly netting the allowance against the sales value of the
gas plant products instead of reporting the allowance as a separate
entry, ONRR may assess a civil penalty under 30 CFR part 1241.
Sec. [thinsp]1206.159 Determination of processing allowances.
(a) Arm's-length processing contracts. (1)(i) For processing costs
incurred by a lessee under an arm's-length contract, the processing
allowance shall be the reasonable actual costs incurred by the lessee
for processing the gas under that contract, except as provided in
paragraphs (a)(1)(ii) and (iii) of this section, subject to monitoring,
review, audit, and adjustment. The lessee shall have the burden of
demonstrating that its contract is arm's-length. ONRR's prior approval
is not required before a lessee may deduct costs incurred under an
arm's-length contract. The lessee must claim a processing allowance by
reporting it as a separate entry on the form ONRR-2014.
(ii) In conducting reviews and audits, ONRR will examine whether
the contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the processor for the
processing. If the contract reflects more than the total consideration,
then the ONRR may require that the processing allowance be determined
in accordance with paragraph (b) of this section.
(iii) If ONRR determines that the consideration paid pursuant to an
arm's-length processing contract does not reflect the reasonable value
of the processing because of misconduct by or between the contracting
parties, or because the lessee otherwise has breached its duty to the
lessor to market the production for the mutual benefit of the lessee
and lessor, then ONRR shall require that the processing allowance be
determined in accordance with paragraph (b) of this section. When ONRR
determines that the value of the processing may be unreasonable, ONRR
will notify the lessee and give the lessee an opportunity to provide
written information justifying the lessee's processing costs.
(2) If an arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
can be determined from the contract, then the processing costs for each
gas plant product shall be determined in accordance with the contract.
No allowance may be taken for the costs of processing lease production
which is not royalty-bearing.
(3) If an arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
cannot be determined from the contract, the lessee shall propose an
allocation procedure to ONRR. The lessee may use its proposed
allocation procedure until ONRR issues its determination. The lessee
shall submit all relevant data to support its proposal. ONRR shall then
determine the processing allowance based upon the lessee's proposal and
any additional information ONRR deems necessary. No processing
allowance will be granted for the costs of processing lease production
which is not royalty bearing. The lessee must submit the allocation
proposal within 3 months of claiming the allocated deduction on form
ONRR-2014.
(4) Where the lessee's payments for processing under an arm's-
length contract are not based on a dollar per unit basis, the lessee
shall convert whatever consideration is paid to a dollar value
equivalent for the purposes of this section.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length processing contract or has no contract, including those
situations where the lessee performs processing for itself, the
processing allowance will be based upon the lessee's reasonable actual
costs as provided in this paragraph. All processing allowances deducted
under a non-arm's-length or no-contract situation are subject to
monitoring, review, audit, and adjustment. The lessee must claim a
processing allowance by reflecting it as a separate entry on the form
ONRR-2014. When necessary or appropriate, ONRR may direct a lessee to
modify its estimated or actual processing allowance.
(2) The processing allowance for non-arm's-length or no-contract
situations shall be based upon the lessee's actual costs for processing
during the reporting
[[Page 36974]]
period, including operating and maintenance expenses, overhead, and
either depreciation and a return on undepreciated capital investment in
accordance with paragraph (b)(2)(iv)(A) of this section, or a cost
equal to the initial depreciable investment in the processing plant
multiplied by a rate of return in accordance with paragraph
(b)(2)(iv)(B) of this section. Allowable capital costs are generally
those costs for depreciable fixed assets (including costs of delivery
and installation of capital equipment) which are an integral part of
the processing plant.
(i) Allowable operating expenses include: Operations supervision
and engineering; operations labor; fuel; utilities; materials; ad
valorem property taxes; rent; supplies; and any other directly
allocable and attributable operating expense which the lessee can
document.
(ii) Allowable maintenance expenses include: Maintenance of the
processing plant; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which
the lessee can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the processing plant is an allowable expense. State
and Federal income taxes and severance taxes, including royalties, are
not allowable expenses.
(iv) A lessee may use either depreciation or a return on
depreciable capital investment. When a lessee has elected to use either
method for a processing plant, the lessee may not later elect to change
to the other alternative without approval of the ONRR.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the processing plant services, or a
unit-of-production method. After an election is made, the lessee may
not change methods without ONRR approval. A change in ownership of a
processing plant shall not alter the depreciation schedule established
by the original processor/lessee for purposes of the allowance
calculation. With or without a change in ownership, a processing plant
shall be depreciated only once. Equipment shall not be depreciated
below a reasonable salvage value.
(B) The ONRR shall allow as a cost an amount equal to the allowable
initial capital investment in the processing plant multiplied by the
rate of return determined pursuant to paragraph (b)(2)(v) of this
section. No allowance shall be provided for depreciation. This
alternative shall apply only to plants first placed in service after
March 1, 1988.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) The processing allowance for each gas plant product shall be
determined based on the lessee's reasonable and actual cost of
processing the gas. Allocation of costs to each gas plant product shall
be based upon generally accepted accounting principles. The lessee may
not take an allowance for the costs of processing lease production
which is not royalty bearing.
(4) A lessee may apply to ONRR for an exception from the
requirement that it compute actual costs in accordance with paragraphs
(b)(1) through (b)(3) of this section. The ONRR may grant the exception
only if: (i) The lessee 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
pursuant to arm's-length processing contracts; if the ONRR grants the
exception, the lessee shall use as its processing allowance the volume
weighted average prices charged other persons pursuant to arm's-length
contracts for processing at the same plant.
(c) Reporting requirements--(1) Arm's-length contracts. (i) The
lessee must notify ONRR of an allowance based on incurred costs by
using a separate entry on the form ONRR-2014.
(ii) ONRR may require that a lessee submit arm's-length processing
contracts and related documents. Documents shall be submitted within a
reasonable time, as determined by ONRR.
(2) Non-arm's-length or no contract. (i) The lessee must notify
ONRR of an allowance based on the incurred costs by using a separate
entry on the form ONRR-2014.
(ii) For new processing plants, the lessee's initial deduction
shall include estimates of the allowable gas processing costs for the
applicable period. Cost estimates shall be based upon the most recently
available operations data for the plant or, if such data are not
available, the lessee shall use estimates based upon industry data for
similar gas processing plants.
(iii) Upon request by ONRR, the lessee shall submit all data used
to prepare the allowance deduction. The data shall be provided within a
reasonable period of time, as determined by ONRR.
(iv) If the lessee is authorized to use the volume weighted average
prices charged other persons as its processing allowance in accordance
with paragraph (b)(4) of this section, it shall follow the reporting
requirements of paragraph (c)(1) of this section.
(d) Interest. (1) If a lessee deducts a processing allowance on its
form ONRR-2014 that exceeds 66 \2/3\ percent of the value of the gas
processed without obtaining prior approval of ONRR under Sec.
1206.158, the lessee shall pay interest on the excess allowance amount
taken from the date such amount is taken to the date the lessee files
an exception request with ONRR.
(2) If a lessee erroneously reports a processing allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(3) Interest required to be paid by this section shall be
determined in accordance with Sec. 1218.54 of this chapter.
(e) Adjustments. (1) If the actual processing allowance is less
than the amount the lessee has taken on form ONRR-2014 for each month
during the allowance reporting period, the lessee shall pay additional
royalties due plus interest computed under Sec. [thinsp]1218.54 of
this chapter from the allowance reporting period when the lessee took
the deduction to the date the lessee repays the difference to ONRR. If
the actual processing allowance is greater than the amount the lessee
has taken on form ONRR-2014 for each month during the allowance
reporting period, the lessee shall be entitled to a credit with
interest.
(2) For lessees processing production from onshore Federal leases,
the lessee must submit a corrected form ONRR-2014 to reflect actual
costs, together with any payment, in accordance with instructions
provided by ONRR.
(3) For lessees processing gas production from leases on the OCS,
if the lessee's estimated processing allowance exceeds the allowance
based on actual costs, the lessee must submit a corrected form ONRR-
2014 to reflect actual costs, together with its payment, in accordance
with instructions provided by ONRR. If the lessee's estimated costs
were less than the actual costs, the refund procedure will be specified
by ONRR.
(f) Other processing cost determinations. The provisions of this
section shall apply to determine processing costs when establishing
value using a net back valuation
[[Page 36975]]
procedure or any other procedure that requires deduction of processing
costs.
Sec. [thinsp]1206.160 Operating allowances.
Notwithstanding any other provisions in these regulations, an
operating allowance may be used for the purpose of computing payment
obligations when specified in the notice of sale and the lease. The
allowance amount or formula shall be specified in the notice of sale
and in the lease agreement.
0
8. Revise subpart F to read as follows:
Subpart F--Federal Coal
Sec.
1206.250 Purpose and scope.
1206.251 Definitions.
1206.252 Information collection.
1206.253 Coal subject to royalties--general provisions.
1206.254 Quality and quantity measurement standards for reporting
and paying royalties.
1206.255 Point of royalty determination.
1206.256 Valuation standards for cents-per-ton leases.
1206.257 Valuation standards for ad valorem leases.
1206.258 Washing allowances--general.
1206.259 Determination of washing allowances.
1206.260 Allocation of washed coal.
1206.261 Transportation allowances--general.
1206.262 Determination of transportation allowances.
1206.263 [Reserved]
1206.264 In-situ and surface gasification and liquefaction
operations.
1206.265 Value enhancement of marketable coal.
Subpart F--Federal Coal
Sec. [thinsp]1206.250 Purpose and scope.
(a) This subpart is applicable to all coal produced from Federal
coal leases. The purpose of this subpart is to establish the value of
coal produced for royalty purposes, of all coal from Federal leases
consistent with the mineral leasing laws, other applicable laws and
lease terms.
(b) If the specific provisions of any statute or settlement
agreement between the United States and a lessee resulting from
administrative or judicial litigation, or any coal lease subject to the
requirements of this subpart, are inconsistent with any regulation in
this subpart then the statute, lease provision, or settlement shall
govern to the extent of that inconsistency.
(c) All royalty payments made to the Office of Natural Resources
Revenue (ONRR) are subject to later audit and adjustment.
Sec. [thinsp]1206.251 Definitions.
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.
Allowance means a deduction used in determining value for royalty
purposes. Coal washing allowance means an allowance for the reasonable,
actual costs incurred by the lessee for coal washing. Transportation
allowance means an allowance for the reasonable, actual costs incurred
by the lessee for moving coal to a point of sale or point of delivery
remote from both the lease and mine or wash plant.
Area means a geographic region in which coal has 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 that has been
arrived at in the marketplace between independent, nonaffiliated
persons with opposing economic interests regarding that contract. For
purposes of this subpart, two persons are affiliated if one person
controls, is controlled by, or is under common control with another
person. For purposes of this subpart, based on the instruments of
ownership of the voting securities of an entity, or based on other
forms of ownership:
(a) Ownership in excess of 50 percent constitutes control;
(b) Ownership of 10 through 50 percent creates a presumption of
control; and
(c) Ownership of less than 10 percent creates a presumption of
noncontrol which ONRR may rebut if it demonstrates actual or legal
control, including the existence of interlocking directorates.
Notwithstanding any other provisions of this subpart, contracts
between relatives, either by blood or by marriage, are not arm's-length
contracts. The ONRR may require the lessee to certify ownership
control. To be considered arm's-length for any production month, a
contract must meet the requirements of this definition for that
production month as well as when the contract was executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty payment
compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the
Interior.
Coal means coal of all ranks from lignite through anthracite.
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).
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by
law that with due consideration creates an obligation.
Gross proceeds (for royalty payment purposes) means the total
monies and other consideration accruing to a coal lessee for the
production and disposition of the coal produced. Gross proceeds
includes, but is not limited to, payments to the lessee for certain
services such as crushing, sizing, screening, storing, mixing, loading,
treatment with substances including chemicals or oils, and other
preparation of the coal to the extent that the lessee is obligated to
perform them at no cost to the Federal Government. Gross proceeds, as
applied to coal, also includes but is not limited to reimbursements for
royalties, taxes or fees, and other reimbursements. Tax reimbursements
are part of the gross proceeds accruing to a lessee even though the
Federal royalty interest may be exempt from taxation. Monies and other
consideration, including the forms of consideration identified in this
paragraph, to which a lessee is contractually or legally entitled but
which it does not seek to collect through reasonable efforts are also
part of gross proceeds.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States for a
Federal coal resource under a mineral leasing law that authorizes
exploration for, development or extraction of, or removal of coal--or
the land covered by that authorization, whichever is required by the
context.
Lessee means any person to whom the United States issues a lease,
and any person who has been assigned an obligation to make royalty or
other payments required by the lease. This includes any person who has
an interest in a lease as well as an operator or payor who has no
interest in the lease but who has assumed the royalty payment
responsibility.
Like-quality coal means coal that has similar chemical and physical
characteristics.
Marketable condition means coal that is sufficiently free from
impurities and otherwise in a condition that it will be accepted by a
purchaser under a sales contract typical for that area.
Mine means an underground or surface excavation or series of
excavations and the surface or underground support facilities that
[[Page 36976]]
contribute directly or indirectly to mining, production, preparation,
and handling of lease products.
Net-back method means a method for calculating market value of coal
at the lease or mine. Under this method, costs of transportation,
washing, handling, etc., are deducted from the ultimate proceeds
received for the coal at the first point at which reasonable values for
the coal may be determined by a sale pursuant to an arm's-length
contract or by comparison to other sales of coal, to ascertain value at
the mine.
Net output means the quantity of washed coal that a washing plant
produces.
Netting is the deduction of an allowance from the sales value by
reporting a one line net sales value, instead of correctly reporting
the deduction as a separate line item on the form ONRR-4430.
Person means by individual, firm, corporation, association,
partnership, consortium, or joint venture.
Sales type code means the contract type or general disposition
(e.g., arm's-length or non-arm's-length) of production from the lease.
The sales type code applies to the sales contract, or other
disposition, and not to the arm's-length or non-arm's-length nature of
a transportation or washing allowance.
Spot market price means the price received under any sales
transaction when planned or actual deliveries span a short period of
time, usually not exceeding one year.
Sec. [thinsp]1206.252 Information collection.
The information collection requirements contained in this subpart
have been approved by the Office of Management and Budget (OMB) under
44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB control
numbers are identified in part 1210--Forms and Reports.
Sec. [thinsp]1206.253 Coal subject to royalties--general provisions.
(a) All coal (except coal unavoidably lost as determined by BLM
under 43 CFR part 3400) from a Federal lease subject to this part is
subject to royalty. This includes coal used, sold, or otherwise
disposed of by the lessee on or off the lease.
(b) If a lessee receives compensation for unavoidably lost coal
through insurance coverage or other arrangements, royalties at the rate
specified in the lease are to be paid on the amount of compensation
received for the coal. No royalty is due on insurance compensation
received by the lessee for other losses.
(c) If waste piles or slurry ponds are reworked to recover coal,
the lessee shall pay royalty at the rate specified in the lease at the
time the recovered coal is used, sold, or otherwise finally disposed
of. The royalty rate shall be that rate applicable to the production
method used to initially mine coal in the waste pile or slurry pond;
i.e., underground mining method or surface mining method. Coal in waste
pits or slurry ponds initially mined from Federal leases shall be
allocated to such leases regardless of whether it is stored on Federal
lands. The lessee shall maintain accurate records to determine to which
individual Federal lease coal in the waste pit or slurry pond should be
allocated. However, nothing in this section requires payment of a
royalty on coal for which a royalty has already been paid.
Sec. [thinsp]1206.254 Quality and quantity measurement standards for
reporting and paying royalties.
For all leases subject to this subpart, the quantity of coal on
which royalty is due shall be measured in short tons (of 2,000 pounds
each) by methods prescribed by the BLM. Coal quantity information will
be reported on appropriate forms required under 30 CFR part 1210--Forms
and Reports.
Sec. [thinsp]1206.255 Point of royalty determination.
(a) For all leases subject to this subpart, royalty shall be
computed on the basis of the quantity and quality of Federal coal in
marketable condition measured at the point of royalty measurement as
determined jointly by BLM and ONRR.
(b) Coal produced and added to stockpiles or inventory does not
require payment of royalty until such coal is later used, sold, or
otherwise finally disposed of. ONRR may ask BLM to increase the lease
bond to protect the lessor's interest when BLM determines that
stockpiles or inventory become excessive so as to increase the risk of
degradation of the resource.
(c) The lessee shall pay royalty at a rate specified in the lease
at the time the coal is used, sold, or otherwise finally disposed of,
unless otherwise provided for at Sec. [thinsp]1206.256(d) of this
subpart.
Sec. [thinsp]1206.256 Valuation standards for cents-per-ton leases.
(a) This section is applicable to coal leases on Federal lands
which provide for the determination of royalty on a cents-per-ton (or
other quantity) basis.
(b) The royalty for coal from leases subject to this section shall
be based on the dollar rate per ton prescribed in the lease. That
dollar rate shall be applicable to the actual quantity of coal used,
sold, or otherwise finally disposed of, including coal which is
avoidably lost as determine by BLM pursuant to 43 CFR part 3400.
(c) For leases subject to this section, there shall be no
allowances for transportation, removal of impurities, coal washing, or
any other processing or preparation of the coal.
(d) When a coal lease is readjusted pursuant to 43 CFR part 3400
and the royalty valuation method changes from a cents-per-ton basis to
an ad valorem basis, coal which is produced prior to the effective date
of readjustment and sold or used within 30 days of the effective date
of readjustment shall be valued pursuant to this section. All coal that
is not used, sold, or otherwise finally disposed of within 30 days
after the effective date of readjustment shall be valued pursuant to
the provisions of Sec. [thinsp]1206.257 of this subpart, and royalties
shall be paid at the royalty rate specified in the readjusted lease.
Sec. [thinsp]1206.257 Valuation standards for ad valorem leases.
(a) This section is applicable to coal leases on Federal lands
which provide for the determination of royalty as a percentage of the
amount of value of coal (ad valorem). The value for royalty purposes of
coal from such leases shall be the value of coal determined under this
section, less applicable coal washing allowances and transportation
allowances determined under Sec. Sec. [thinsp]1206.258 through
1206.262 of this subpart, or any allowance authorized by Sec.
[thinsp]1206.265 of this subpart. The royalty due shall be equal to the
value for royalty purposes multiplied by the royalty rate in the lease.
(b)(1) The value of coal that is sold pursuant to an arm's-length
contract shall be the gross proceeds accruing to the lessee, except as
provided in paragraphs (b)(2), (3), and (5) of this section. The lessee
shall have the burden of demonstrating that its contract is arm's-
length. The value which the lessee reports, for royalty purposes, is
subject to monitoring, review, and audit.
(2) In conducting reviews and audits, ONRR will examine whether the
contract reflects the total consideration actually transferred either
directly or indirectly from the buyer to the seller for the coal
produced. If the contract does not reflect the total consideration,
then the ONRR may require that the coal sold pursuant to that contract
be valued in accordance with paragraph (c) of this section. Value may
not be based on less than the gross proceeds accruing to the lessee for
the coal production, including the additional consideration.
[[Page 36977]]
(3) If ONRR determines that the gross proceeds accruing to the
lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the production because of misconduct by or between
the contracting parties, or because the lessee otherwise has breached
its duty to the lessor to market the production for the mutual benefit
of the lessee and the lessor, then ONRR shall require that the coal
production be valued pursuant to paragraph (c)(2)(ii), (iii), (iv), or
(v) of this section, and in accordance with the notification
requirements of paragraph (d)(3) of this section. When ONRR determines
that the value may be unreasonable, ONRR will notify the lessee and
give the lessee an opportunity to provide written information
justifying the lessee's reported coal value.
(4) ONRR may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the coal production.
(5) The value of production for royalty purposes shall not include
payments received by the lessee pursuant to a contract which the lessee
demonstrates, to ONRR's satisfaction, were not part of the total
consideration paid for the purchase of coal production.
(c)(1) The value of coal from leases subject to this section and
which is not sold pursuant to an arm's-length contract shall be
determined in accordance with this section.
(2) If the value of the coal cannot be determined pursuant to
paragraph (b) of this section, then the value shall be determined
through application of other valuation criteria. The criteria shall be
considered in the following order, and the value shall be based upon
the first applicable criterion:
(i) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition of produced
coal by other than an arm's-length contract), provided that those gross
proceeds are within the range of the gross proceeds derived from, or
paid under, comparable arm's-length contracts between buyers and
sellers neither of whom is affiliated with the lessee for sales,
purchases, or other dispositions of like-quality coal produced in the
area. In evaluating the comparability of arm's-length contracts for the
purposes of these regulations, the following factors shall be
considered: Price, time of execution, duration, market or markets
served, terms, quality of coal, quantity, and such other factors as may
be appropriate to reflect the value of the coal;
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information
Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to,
published or publicly available spot market prices, or information
submitted by the lessee concerning circumstances unique to a particular
lease operation or the saleability of certain types of coal;
(v) If a reasonable value cannot be determined using paragraphs
(c)(2) (i), (ii), (iii), or (iv) of this section, then a net-back
method or any other reasonable method shall be used to determine value.
(3) When the value of coal is determined pursuant to paragraph
(c)(2) of this section, that value determination shall be consistent
with the provisions contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of
this section, that value does not require ONRR's prior approval.
However, the lessee shall retain all data relevant to the determination
of royalty value. Such data shall be subject to review and audit, and
ONRR will direct a lessee to use a different value if it determines
that the reported value is inconsistent with the requirements of these
regulations.
(2) Any Federal lessee will make available upon request to the
authorized ONRR or State representatives, to the Inspector General of
the Department of the Interior or other persons authorized to receive
such information, arm's-length sales value and sales quantity data for
like-quality coal sold, purchased, or otherwise obtained by the lessee
from the area.
(3) A lessee shall notify ONRR if it has determined value pursuant
to paragraphs (c)(2)(ii), (iii), (iv), or (v) of this section. The
notification shall be by letter to the Director for Office of Natural
Resources Revenue of his/her designee. The letter shall identify the
valuation method to be used and contain a brief description of the
procedure to be followed. The notification required by this section is
a one-time notification due no later than the month the lessee first
reports royalties on the form ONRR-4430 using a valuation method
authorized by paragraphs (c)(2)(ii), (iii), (iv), or (v) of this
section, and each time there is a change in a method under paragraphs
(c)(2)(iv) or (v) of this section.
(e) If ONRR determines that a lessee has not properly determined
value, the lessee shall be liable for the difference, if any, between
royalty payments made based upon the value it has used and the royalty
payments that are due based upon the value established by ONRR. The
lessee shall also be liable for interest computed pursuant to Sec.
[thinsp]1218.202 of this chapter. If the lessee is entitled to a
credit, ONRR will provide instructions for the taking of that credit.
(f) The lessee may request a value determination from ONRR. In that
event, the lessee shall propose to ONRR a value determination method,
and may use that method in determining value for royalty purposes until
ONRR issues its decision. The lessee shall submit all available data
relevant to its proposal. The ONRR shall expeditiously determine the
value based upon the lessee's proposal and any additional information
ONRR deems necessary. That determination shall remain effective for the
period stated therein. After ONRR issues its determination, the lessee
shall make the adjustments in accordance with paragraph (e) of this
section.
(g) Notwithstanding any other provisions of this section, under no
circumstances shall the value for royalty purposes be less than the
gross proceeds accruing to the lessee for the disposition of produced
coal less applicable provisions of paragraph (b)(5) of this section and
less applicable allowances determined pursuant to Sec. Sec.
[thinsp]1206.258 through 1206.262 and 1206.265 of this subpart.
(h) The lessee is required to place coal in marketable condition at
no cost to the Federal Government. Where the value established under
this section is determined by a lessee's gross proceeds, that value
shall be increased to the extent that the gross proceeds has been
reduced because the purchaser, or any other person, is providing
certain services, the cost of which ordinarily is the responsibility of
the lessee to place the coal in marketable condition.
(i) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled, it
must pay royalty at a value based upon that obtainable price or
benefit. Contract revisions or amendments shall be in writing and
signed by all parties to an arm's-length contract, and may be
retroactively applied to value for royalty purposes for a period not to
exceed two years, unless ONRR approves a longer period. If the lessee
makes timely application for a price increase allowed under its
contract but the purchaser refuses, and the lessee takes reasonable
measures,
[[Page 36978]]
which are documented, to force purchaser compliance, the lessee will
owe no additional royalties unless or until monies or consideration
resulting from the price increase are received. This paragraph shall
not be construed to permit a lessee to avoid its royalty payment
obligation in situations where a purchaser fails to pay, in whole or in
part or timely, for a quantity of coal.
(j) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by ONRR of value under this section
shall be considered final or binding as against the Federal Government
or its beneficiaries until the audit period is formally closed.
(k) Certain information submitted to ONRR to support valuation
proposals, including transportation, coal washing, or other allowances
under Sec. [thinsp]1206.265 of this subpart, is exempted from
disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data
specified by the Act to be privileged, confidential, or otherwise
exempt shall be maintained in a confidential manner in accordance with
applicable law and regulations. All requests for information about
determinations made under this part are to be submitted in accordance
with the Freedom of Information Act regulation of the Department of the
Interior, 43 CFR part 2.
Sec. [thinsp]1206.258 Washing allowances--general.
(a) For ad valorem leases subject to Sec. [thinsp]1206.257 of this
subpart, ONRR shall, as authorized by this section, allow a deduction
in determining value for royalty purposes for the reasonable, actual
costs incurred to wash coal, unless the value determined pursuant to
Sec. [thinsp]1206.257 of this subpart was based upon like-quality
unwashed coal. Under no circumstances will the authorized washing
allowance and the transportation allowance reduce the value for royalty
purposes to zero.
(b) If ONRR determines that a lessee has improperly determined a
washing allowance authorized by this section, then the lessee shall be
liable for any additional royalties, plus interest determined in
accordance with Sec. [thinsp]1218.202 of this chapter, or shall be
entitled to a credit without interest.
(c) Lessees shall not disproportionately allocate washing costs to
Federal leases.
(d) No cost normally associated with mining operations and which
are necessary for placing coal in marketable condition shall be allowed
as a cost of washing.
(e) Coal washing costs shall only be recognized as allowances when
the washed coal is sold and royalties are reported and paid.
Sec. [thinsp]1206.259 Determination of washing allowances.
(a) Arm's-length contracts. (1) For washing costs incurred by a
lessee under an arm's-length contract, the washing allowance shall be
the reasonable actual costs incurred by the lessee for washing the coal
under that contract, subject to monitoring, review, audit, and possible
future adjustment. The lessee shall have the burden of demonstrating
that its contract is arm's-length. ONRR's prior approval is not
required before a lessee may deduct costs incurred under an arm's-
length contract. The lessee must claim a washing allowance by reporting
it as a separate line entry on the form ONRR-4430.
(2) In conducting reviews and audits, ONRR will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the washer for the
washing. If the contract reflects more than the total consideration
paid, then the ONRR may require that the washing allowance be
determined in accordance with paragraph (b) of this section.
(3) If ONRR determines that the consideration paid pursuant to an
arm's-length washing contract does not reflect the reasonable value of
the washing because of misconduct by or between the contracting
parties, or because the lessee otherwise has breached its duty to the
lessor to market the production for the mutual benefit of the lessee
and the lessor, then ONRR shall require that the washing allowance be
determined in accordance with paragraph (b) of this section. When ONRR
determines that the value of the washing may be unreasonable, ONRR will
notify the lessee and give the lessee an opportunity to provide written
information justifying the lessee's washing costs.
(4) Where the lessee's payments for washing under an arm's-length
contract are not based on a dollar-per-unit basis, the lessee shall
convert whatever consideration is paid to a dollar value equivalent.
Washing allowances shall be expressed as a cost per ton of coal washed.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations
where the lessee performs washing for itself, the washing allowance
will be based upon the lessee's reasonable actual costs. All washing
allowances deducted under a non-arm's-length or no contract situation
are subject to monitoring, review, audit, and possible future
adjustment. The lessee must claim a washing allowance by reporting it
as a separate line entry on the form ONRR-4430. When necessary or
appropriate, ONRR may direct a lessee to modify its estimated or actual
washing allowance.
(2) The washing allowance for non-arm's-length or no contract
situations shall be based upon the lessee's actual costs for washing
during the reported period, including operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv) (A) of this section, or a cost equal to the depreciable
investment in the wash plant multiplied by the rate of return in
accordance with paragraph (b)(2)(iv)(B) of this section. Allowable
capital costs are generally those for depreciable fixed assets
(including costs of delivery and installation of capital equipment)
which are an integral part of the wash plant.
(i) Allowable operating expenses include: Operations supervision
and engineering; operations labor; fuel; utilities; materials; ad
valorem property taxes, rent; supplies; and any other directly
allocable and attributable operating expense which the lessee can
document.
(ii) Allowable maintenance expenses include: Maintenance of the
wash plant; maintenance of equipment; maintenance labor; and other
directly allocable and attributable maintenance expenses which the
lessee can document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the wash plant is an allowable expense. State and
Federal income taxes and severance taxes, including royalties, are not
allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this
section. After a lessee has elected to use either method for a wash
plant, the lessee may not later elect to change to the other
alternative without approval of the ONRR.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the wash plant services, whichever is
appropriate, or a unit of production method. After an election is made,
the lessee may not change methods without ONRR approval. A change in
ownership of a wash plant shall not alter the depreciation schedule
established by the original operator/lessee for purposes of the
allowance calculation. With or without a change in
[[Page 36979]]
ownership, a wash plant shall be depreciated only once. Equipment shall
not be depreciated below a reasonable salvage value.
(B) ONRR shall allow as a cost an amount equal to the allowable
capital investment in the wash plant multiplied by the rate of return
determined pursuant to paragraph (b)(2)(v) of this section. No
allowance shall be provided for depreciation. This alternative shall
apply only to plants first placed in service or acquired after March 1,
1989.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) The washing allowance for coal shall be determined based on the
lessee's reasonable and actual cost of washing the coal. The lessee may
not take an allowance for the costs of washing lease production that is
not royalty bearing.
(c) Reporting requirements--(1) Arm's-length contracts. (i) The
lessee must notify ONRR of an allowance based on incurred costs by
using a separate line entry on the form ONRR-4430.
(ii) ONRR may require that a lessee submit arm's-length washing
contracts and related documents. Documents shall be submitted within a
reasonable time, as determined by ONRR.
(2) Non-arm's-length or no contract. (i) The lessee must notify
ONRR of an allowance based on the incurred costs by using a separate
line entry on the form ONRR-4430.
(ii) For new washing facilities or arrangements, the lessee's
initial washing deduction shall include estimates of the allowable coal
washing costs for the applicable period. Cost estimates shall be based
upon the most recently available operations data for the washing system
or, if such data are not available, the lessee shall use estimates
based upon industry data for similar washing systems.
(iii) Upon request by ONRR, the lessee shall submit all data used
to prepare the allowance deduction. The data shall be provided within a
reasonable period of time, as determined by ONRR.
(d) Interest and assessments. (1) If a lessee nets a washing
allowance on the form ONRR-4430, then the lessee shall be assessed an
amount up to 10 percent of the allowance netted not to exceed $250 per
lease sales type code per sales period.
(2) If a lessee erroneously reports a washing allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(3) Interest required to be paid by this section shall be
determined in accordance with Sec. [thinsp]1218.202 of this chapter.
(e) Adjustments. (1) If the actual coal washing allowance is less
than the amount the lessee has taken on form ONRR-4430 for each month
during the allowance reporting period, the lessee shall pay additional
royalties due plus interest computed under Sec. [thinsp]1218.202 of
this chapter from the date when the lessee took the deduction to the
date the lessee repays the difference to ONRR. If the actual washing
allowance is greater than the amount the lessee has taken on form ONRR-
4430 for each month during the allowance reporting period, the lessee
shall be entitled to a credit without interest.
(2) The lessee must submit a corrected form ONRR-4430 to reflect
actual costs, together with any payment, in accordance with
instructions provided by ONRR.
(f) Other washing cost determinations. The provisions of this
section shall apply to determine washing costs when establishing value
using a net-back valuation procedure or any other procedure that
requires deduction of washing costs.
Sec. [thinsp]1206.260 Allocation of washed coal.
(a) When coal is subjected to washing, the washed coal must be
allocated to the leases from which it was extracted.
(b) When the net output of coal from a washing plant is derived
from coal obtained from only one lease, the quantity of washed coal
allocable to the lease will be based on the net output of the washing
plant.
(c) When the net output of coal from a washing plant is derived
from coal obtained from more than one lease, unless determined
otherwise by BLM, the quantity of net output of washed coal allocable
to each lease will be based on the ratio of measured quantities of coal
delivered to the washing plant and washed from each lease compared to
the total measured quantities of coal delivered to the washing plant
and washed.
Sec. [thinsp]1206.261 Transportation allowances--general.
(a) For ad valorem leases subject to Sec. [thinsp]1206.257 of this
subpart, where the value for royalty purposes has been determined at a
point remote from the lease or mine, ONRR shall, as authorized by this
section, allow a deduction in determining value for royalty purposes
for the reasonable, actual costs incurred to:
(1) Transport the coal from a Federal lease to a sales point which
is remote from both the lease and mine; or
(2) 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. In-mine transportation
costs shall not be included in the transportation allowance.
(b) Under no circumstances will the authorized washing allowance
and the transportation allowance reduce the value for royalty purposes
to zero.
(c)(1) When coal transported from a mine to a wash plant is
eligible for a transportation allowance in accordance with this
section, the lessee is not required to allocate transportation costs
between the quantity of clean coal output and the rejected waste
material. The transportation allowance shall be authorized for the
total production which is transported. Transportation allowances shall
be expressed as a cost per ton of cleaned coal transported.
(2) For coal that is not washed at a wash plant, the transportation
allowance shall be authorized for the total production which is
transported. Transportation allowances shall be expressed as a cost per
ton of coal transported.
(3) Transportation costs shall only be recognized as allowances
when the transported coal is sold and royalties are reported and paid.
(d) If, after a review and/or audit, ONRR determines that a lessee
has improperly determined a transportation allowance authorized by this
section, then the lessee shall pay any additional royalties, plus
interest, determined in accordance with Sec. [thinsp]1218.202 of this
chapter, or shall be entitled to a credit, without interest.
(e) Lessees shall not disproportionately allocate transportation
costs to Federal leases.
Sec. [thinsp]1206.262 Determination of transportation allowances.
(a) Arm's-length contracts. (1) For transportation costs incurred
by a lessee pursuant to an arm's-length contract, the transportation
allowance shall be the reasonable, actual costs incurred by the lessee
for transporting the coal under that contract, subject to monitoring,
review, audit, and possible future adjustment. The lessee shall have
the burden of demonstrating that its contract is arm's-length. The
lessee must claim a transportation allowance by
[[Page 36980]]
reporting it as a separate line entry on the form ONRR-4430.
(2) In conducting reviews and audits, ONRR will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the transporter for
the transportation. If the contract reflects more than the total
consideration paid, then the ONRR may require that the transportation
allowance be determined in accordance with paragraph (b) of this
section.
(3) If ONRR determines that the consideration paid pursuant to an
arm's-length transportation contract does not reflect the reasonable
value of the transportation because of misconduct by or between the
contracting parties, or because the lessee otherwise has breached its
duty to the lessor to market the production for the mutual benefit of
the lessee and the lessor, then ONRR shall require that the
transportation allowance be determined in accordance with paragraph (b)
of this section. When ONRR determines that the value of the
transportation may be unreasonable, ONRR will notify the lessee and
give the lessee an opportunity to provide written information
justifying the lessee's transportation costs.
(4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar-per-unit basis, the lessee
shall convert whatever consideration is paid to a dollar value
equivalent for the purposes of this section.
(b) Non-arm's-length or no contract--(1) If a lessee has a non-
arm's-length contract or has no contract, including those situations
where the lessee performs transportation services for itself, the
transportation allowance will be based upon the lessee's reasonable
actual costs. All transportation allowances deducted under a non-arm's-
length or no contract situation are subject to monitoring, review,
audit, and possible future adjustment. The lessee must claim a
transportation allowance by reporting it as a separate line entry on
the form ONRR-4430. When necessary or appropriate, ONRR may direct a
lessee to modify its estimated or actual transportation allowance
deduction.
(2) The transportation allowance for non-arm's-length or no-
contract situations shall be based upon the lessee's actual costs for
transportation during the reporting period, including operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable
investment in the transportation system multiplied by the rate of
return in accordance with paragraph (b)(2)(iv)(B) of this section.
Allowable capital costs are generally those for depreciable fixed
assets (including costs of delivery and installation of capital
equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision
and engineering; operations labor; fuel; utilities; materials; ad
valorem property taxes; rent; supplies; and any other directly
allocable and attributable operating expense which the lessee can
document.
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which
the lessee can document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the transportation system is an allowable expense. State
and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this
section. After a lessee has elected to use either method for a
transportation system, the lessee may not later elect to change to the
other alternative without approval of ONRR.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services,
whichever is appropriate, or a unit of production method. After an
election is made, the lessee may not change methods without ONRR
approval. A change in ownership of a transportation system shall not
alter the depreciation schedule established by the original
transporter/lessee for purposes of the allowance calculation. With or
without a change in ownership, a transportation system shall be
depreciated only once. Equipment shall not be depreciated below a
reasonable salvage value.
(B) ONRR shall allow as a cost an amount equal to the allowable
capital investment in the transportation system multiplied by the rate
of return determined pursuant to paragraph (b)(2)(B)(v) of this
section. No allowance shall be provided for depreciation. This
alternative shall apply only to transportation facilities first placed
in service or acquired after March 1, 1989.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) A lessee may apply to ONRR for exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1) and
(2) of this section. ONRR will grant the exception only if the lessee
has a rate for the transportation approved by a Federal agency or by a
State regulatory agency (for Federal leases). ONRR shall deny the
exception request if it determines that the rate is excessive as
compared to arm's-length transportation charges by systems, owned by
the lessee or others, providing similar transportation services in that
area. If there are no arm's-length transportation charges, ONRR shall
deny the exception request if:
(i) No Federal or State regulatory agency costs analysis exists and
the Federal or State regulatory agency, as applicable, has declined to
investigate under ONRR timely objections upon filing; and
(ii) The rate significantly exceeds the lessee's actual costs for
transportation as determined under this section.
(c) Reporting requirements--(1) Arm's-length contracts. (i) The
lessee must notify ONRR of an allowance based on incurred costs by
using a separate line entry on the form ONRR-4430.
(ii) ONRR may require that a lessee submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents. Documents shall be submitted within a reasonable
time, as determined by ONRR.
(2) Non-arm's-length or no contract--(i) The lessee must notify
ONRR of an allowance based on the incurred costs by using a separate
line entry on form ONRR-4430.
(ii) For new transportation facilities or arrangements, the
lessee's initial deduction shall include estimates of the allowable
coal transportation costs for the applicable period. Cost estimates
shall be based upon the most recently available operations data for the
transportation system or, if such data are not available, the lessee
shall use estimates based upon industry data for similar transportation
systems.
(iii) Upon request by ONRR, the lessee shall submit all data used
to prepare the allowance deduction. The data shall be provided within a
reasonable period of time, as determined by ONRR.
[[Page 36981]]
(iv) If the lessee is authorized to use its Federal- or State-
agency-approved rate as its transportation cost in accordance with
paragraph (b)(3) of this section, it shall follow the reporting
requirements of paragraph (c)(1) of this section.
(d) Interest and assessments. (1) If a lessee nets a transportation
allowance on form ONRR-4430, the lessee shall be assessed an amount of
up to 10 percent of the allowance netted not to exceed $250 per lease
sales type code per sales period.
(2) If a lessee erroneously reports a transportation allowance
which results in an underpayment of royalties, interest shall be paid
on the amount of that underpayment.
(3) Interest required to be paid by this section shall be
determined in accordance with Sec. [thinsp]1218.202 of this chapter.
(e) Adjustments. (1) If the actual coal transportation allowance is
less than the amount the lessee has taken on form ONRR-4430 for each
month during the allowance reporting period, the lessee shall pay
additional royalties due plus interest computed under Sec.
[thinsp]1218.202 of this chapter from the date when the lessee took the
deduction to the date the lessee repays the difference to ONRR. If the
actual transportation allowance is greater than amount the lessee has
taken on form ONRR-4430 for each month during the allowance reporting
period, the lessee shall be entitled to a credit without interest.
(2) The lessee must submit a corrected form ONRR-4430 to reflect
actual costs, together with any payments, in accordance with
instructions provided by ONRR.
(f) Other transportation cost determinations. The provisions of
this section shall apply to determine transportation costs when
establishing value using a net-back valuation procedure or any other
procedure that requires deduction of transportation costs.
Sec. [thinsp]1206.263 [Reserved]
Sec. [thinsp]1206.264 In-situ and surface gasification and
liquefaction operations.
If an ad valorem Federal coal lease is developed by in-situ or
surface gasification or liquefaction technology, the lessee shall
propose the value of coal for royalty purposes to ONRR. The ONRR will
review the lessee's proposal and issue a value determination. The
lessee may use its proposed value until ONRR issues a value
determination.
Sec. [thinsp]1206.265 Value enhancement of marketable coal.
If, prior to use, sale, or other disposition, the lessee enhances
the value of coal after the coal has been placed in marketable
condition in accordance with Sec. [thinsp]1206.257(h) of this subpart,
the lessee shall notify ONRR that such processing is occurring or will
occur. The value of that production shall be determined as follows:
(a) A value established for the feedstock coal in marketable
condition by application of the provisions of Sec.
[thinsp]1206.257(c)(2)(i) through (iv) of this subpart; or,
(b) In the event that a value cannot be established in accordance
with paragraph (a) of this section, then the value of production will
be determined in accordance with Sec. [thinsp]1206.257(c)(2)(v) of
this subpart and the value shall be the lessee's gross proceeds
accruing from the disposition of the enhanced product, reduced by ONRR-
approved processing costs and procedures including a rate of return on
investment equal to two times the Standard and Poor's BBB bond rate
applicable under Sec. [thinsp]1206.259(b)(2)(v) of this subpart.
0
9. Revise subpart J to read as follows:
Subpart J--Indian Coal
Sec.
1206.450 Purpose and scope.
1206.451 Definitions.
1206.452 Coal subject to royalties--general provisions.
1206.453 Quality and quantity measurement standards for reporting
and paying royalties.
1206.454 Point of royalty determination.
1206.455 Valuation standards for cents-per-ton leases.
1206.456 Valuation standards for ad valorem leases.
1206.457 Washing allowances--general.
1206.458 Determination of washing allowances.
1206.459 Allocation of washed coal.
1206.460 Transportation allowances--general.
1206.461 Determination of transportation allowances.
1206.462 [Reserved]
1206.463 In-situ and surface gasification and liquefaction
operations.
1206.464 Value enhancement of marketable coal.
Subpart J--Indian Coal
Sec. [thinsp]1206.450 Purpose and scope.
(a) This subpart prescribes the procedures to establish the value,
for royalty purposes, of all coal from Indian Tribal and allotted
leases (except leases on the Osage Indian Reservation, Osage County,
Oklahoma).
(b) If the specific provisions of any statute, treaty, or
settlement agreement between the Indian lessor and a lessee resulting
from administrative or judicial litigation, or any coal lease subject
to the requirements of this subpart, are inconsistent with any
regulation in this subpart, then the statute, treaty, lease provision,
or settlement shall govern to the extent of that inconsistency.
(c) All royalty payments are subject to later audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the
trust responsibilities of the United States with respect to the
administration of Indian coal leases are discharged in accordance with
the requirements of the governing mineral leasing laws, treaties, and
lease terms.
Sec. [thinsp]1206.451 Definitions.
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.
Allowance means an approved, or an ONRR-initially accepted
deduction in determining value for royalty purposes. Coal washing
allowance means an allowance for the reasonable, actual costs incurred
by the lessee for coal washing, or an approved or ONRR-initially
accepted deduction for the costs of washing coal, determined pursuant
to this subpart. Transportation allowance means an allowance for the
reasonable, actual costs incurred by the lessee for moving coal to a
point of sale or point of delivery remote from both the lease and mine
or wash plant, or an approved ONRR-initially accepted deduction for
costs of such transportation, determined pursuant to this subpart.
Area means a geographic region in which coal has 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 that has been
arrived at in the marketplace between independent, nonaffiliated
persons with opposing economic interests regarding that contract. For
purposes of this subpart, two persons are affiliated if one person
controls, is controlled by, or is under common control with another
person. For purposes of this subpart, based on the instruments of
ownership of the voting securities of an entity, or based on other
forms of ownership: Ownership in excess of 50 percent constitutes
control; ownership of 10 through 50 percent creates a presumption of
control; and ownership of less than 10 percent creates a presumption of
noncontrol which ONRR may rebut if it demonstrates actual or legal
control, including the existence of interlocking directorates.
[[Page 36982]]
Notwithstanding any other provisions of this subpart, contracts between
relatives, either by blood or by marriage, are not arm's-length
contracts. ONRR may require the lessee to certify ownership control. To
be considered arm's-length for any production month, a contract must
meet the requirements of this definition for that production month, as
well as when the contract was executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty payment
compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on 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.
Coal means coal of all ranks from lignite through anthracite.
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).
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by
law that with due consideration creates an obligation.
Gross proceeds (for royalty payment purposes) means the total
monies and other consideration accruing to a coal lessee for the
production and disposition of the coal produced. Gross proceeds
includes, but is not limited to, payments to the lessee for certain
services such as crushing, sizing, screening, storing, mixing, loading,
treatment with substances including chemicals or oils, and other
preparation of the coal to the extent that the lessee is obligated to
perform them at no cost to the Indian lessor. Gross proceeds, as
applied to coal, also includes but is not limited to reimbursements for
royalties, taxes or fees, and other reimbursements. Tax reimbursements
are part of the gross proceeds accruing to a lessee even though the
Indian royalty interest may be exempt from taxation. Monies and other
consideration, including the forms of consideration identified in this
paragraph, to which a lessee is contractually or legally entitled but
which it does not seek to collect through reasonable efforts are also
part of gross proceeds.
Indian allottee means any Indian for whom land or an interest in
land is held in trust by the United States or who holds title subject
to Federal restriction against alienation.
Indian Tribe means any Indian Tribe, band, nation, pueblo,
community, rancheria, colony, or other group of Indians for which any
land or interest in land is held in trust by the United States or which
is subject to Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States for an
Indian coal resource under a mineral leasing law that authorizes
exploration for, development or extraction of, or removal of coal--or
the land covered by that authorization, whichever is required by the
context.
Lessee means any person to whom the Indian Tribe or an Indian
allottee issues a lease, and any person who has been assigned an
obligation to make royalty or other payments required by the lease.
This includes any person who has an interest in a lease as well as an
operator or payor who has no interest in the lease but who has assumed
the royalty payment responsibility.
Like-quality coal means coal that has similar chemical and physical
characteristics.
Marketable condition means coal that is sufficiently free from
impurities and otherwise in a condition that it will be accepted by a
purchaser under a sales contract typical for that area.
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.
Net-back method means a method for calculating market value of coal
at the lease or mine. Under this method, costs of transportation,
washing, handling, etc., are deducted from the ultimate proceeds
received for the coal at the first point at which reasonable values for
the coal may be determined by a sale pursuant to an arm's-length
contract or by comparison to other sales of coal, to ascertain value at
the mine.
Net output means the quantity of washed coal that a washing plant
produces.
ONRR means the Office of Natural Resources Revenue of the
Department of the Interior.
Person means by individual, firm, corporation, association,
partnership, consortium, or joint venture.
Sales type code means the contract type or general disposition
(e.g., arm's-length or non-arm's-length) of production from the lease.
The sales type code applies to the sales contract, or other
disposition, and not to the arm's-length or non-arm's-length nature of
a transportation or washing allowance.
Spot market price means the price received under any sales
transaction when planned or actual deliveries span a short period of
time, usually not exceeding one year.
Sec. [thinsp]1206.452 Coal subject to royalties--general provisions.
(a) All coal (except coal unavoidably lost as determined by BLM
pursuant to 43 CFR group 3400) from an Indian lease subject to this
part is subject to royalty. This includes coal used, sold, or otherwise
disposed of by the lessee on or off the lease.
(b) If a lessee receives compensation for unavoidably lost coal
through insurance coverage or other arrangements, royalties at the rate
specified in the lease are to be paid on the amount of compensation
received for the coal. No royalty is due on insurance compensation
received by the lessee for other losses.
(c) If waste piles or slurry ponds are reworked to recover coal,
the lessee shall pay royalty at the rate specified in the lease at the
time the recovered coal is used, sold, or otherwise finally disposed
of. The royalty rate shall be that rate applicable to the production
method used to initially mine coal in the waste pile or slurry pond;
i.e., underground mining method or surface mining method. Coal in waste
pits or slurry ponds initially mined from Indian leases shall be
allocated to such leases regardless of whether it is stored on Indian
lands. The lessee shall maintain accurate records to determine to which
individual Indian lease coal in the waste pit or slurry pond should be
allocated. However, nothing in this section requires payment of a
royalty on coal for which a royalty has already been paid.
Sec. [thinsp]1206.453 Quality and quantity measurement standards for
reporting and paying royalties.
For all leases subject to this subpart, the quantity of coal on
which royalty is due shall be measured in short tons (of 2,000 pounds
each) by methods prescribed by the BLM. Coal quantity information will
be reported on appropriate forms required under 30 CFR part 1210--Forms
and Reports.
Sec. 1206.454 Point of royalty determination.
(a) For all leases subject to this subpart, royalty shall be
computed on the basis of the quantity and quality of Indian coal in
marketable condition measured at the point of royalty
[[Page 36983]]
measurement as determined jointly by BLM and ONRR.
(b) Coal produced and added to stockpiles or inventory does not
require payment of royalty until such coal is later used, sold, or
otherwise finally disposed of. ONRR may ask BLM or BIA to increase the
lease bond to protect the lessor's interest when BLM determines that
stockpiles or inventory become excessive so as to increase the risk of
degradation of the resource.
(c) The lessee shall pay royalty at a rate specified in the lease
at the time the coal is used, sold, or otherwise finally disposed of,
unless otherwise provided for at Sec. [thinsp]1206.455(d) of this
subpart.
Sec. [thinsp]1206.455 Valuation standards for cents-per-ton leases.
(a) This section is applicable to coal leases on Indian Tribal and
allotted Indian lands (except leases on the Osage Indian Reservation,
Osage County, Oklahoma) which provide for the determination of royalty
on a cents-per-ton (or other quantity) basis.
(b) The royalty for coal from leases subject to this section shall
be based on the dollar rate per ton prescribed in the lease. That
dollar rate shall be applicable to the actual quantity of coal used,
sold, or otherwise finally disposed of, including coal which is
avoidably lost as determined by BLM pursuant to 43 CFR part 3400.
(c) For leases subject to this section, there shall be no
allowances for transportation, removal of impurities, coal washing, or
any other processing or preparation of the coal.
(d) When a coal lease is readjusted pursuant to 43 CFR part 3400
and the royalty valuation method changes from a cents-per-ton basis to
an ad valorem basis, coal which is produced prior to the effective date
of readjustment and sold or used within 30 days of the effective date
of readjustment shall be valued pursuant to this section. All coal that
is not used, sold, or otherwise finally disposed of within 30 days
after the effective date of readjustment shall be valued pursuant to
the provisions of Sec. [thinsp]1206.456 of this subpart, and royalties
shall be paid at the royalty rate specified in the readjusted lease.
Sec. [thinsp]1206.456 Valuation standards for ad valorem leases.
(a) This section is applicable to coal leases on Indian Tribal and
allotted Indian lands (except leases on the Osage Indian Reservation,
Osage County, Oklahoma) which provide for the determination of royalty
as a percentage of the amount of value of coal (ad valorem). The value
for royalty purposes of coal from such leases shall be the value of
coal determined pursuant to this section, less applicable coal washing
allowances and transportation allowances determined pursuant to
Sec. Sec. [thinsp]1206.457 through 1206.461 of this subpart, or any
allowance authorized by Sec. [thinsp]1206.464 of this subpart. The
royalty due shall be equal to the value for royalty purposes multiplied
by the royalty rate in the lease.
(b)(1) The value of coal that is sold pursuant to an arm's-length
contract shall be the gross proceeds accruing to the lessee, except as
provided in paragraphs (b)(2), (3), and (5) of this section. The lessee
shall have the burden of demonstrating that its contract is arm's-
length. The value which the lessee reports, for royalty purposes, is
subject to monitoring, review, and audit.
(2) In conducting reviews and audits, ONRR will examine whether the
contract reflects the total consideration actually transferred either
directly or indirectly from the buyer to the seller for the coal
produced. If the contract does not reflect the total consideration,
then ONRR may require that the coal sold pursuant to that contract be
valued in accordance with paragraph (c) of this section. Value may not
be based on less than the gross proceeds accruing to the lessee for the
coal production, including the additional consideration.
(3) If ONRR determines that the gross proceeds accruing to the
lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the production because of misconduct by or between
the contracting parties, or because the lessee otherwise has breached
its duty to the lessor to market the production for the mutual benefit
of the lessee and the lessor, then ONRR shall require that the coal
production be valued pursuant to paragraphs (c)(2)(ii), (iii), (iv), or
(v) of this section, and in accordance with the notification
requirements of paragraph (d)(3) of this section. When ONRR determines
that the value may be unreasonable, ONRR will notify the lessee and
give the lessee an opportunity to provide written information
justifying the lessee's reported coal value.
(4) ONRR may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the coal production.
(5) The value of production for royalty purposes shall not include
payments received by the lessee pursuant to a contract which the lessee
demonstrates, to ONRR's satisfaction, were not part of the total
consideration paid for the purchase of coal production.
(c)(1) The value of coal from leases subject to this section and
which is not sold pursuant to an arm's-length contract shall be
determined in accordance with this section.
(2) If the value of the coal cannot be determined pursuant to
paragraph (b) of this section, then the value shall be determined
through application of other valuation criteria. The criteria shall be
considered in the following order, and the value shall be based upon
the first applicable criterion:
(i) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition of produced
coal by other than an arm's-length contract), provided that those gross
proceeds are within the range of the gross proceeds derived from, or
paid under, comparable arm's-length contracts between buyers and
sellers neither of whom is affiliated with the lessee for sales,
purchases, or other dispositions of like-quality coal produced in the
area. In evaluating the comparability of arm's-length contracts for the
purposes of these regulations, the following factors shall be
considered: Price, time of execution, duration, market or markets
served, terms, quality of coal, quantity, and such other factors as may
be appropriate to reflect the value of the coal;
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information
Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to,
published or publicly available spot market prices, or information
submitted by the lessee concerning circumstances unique to a particular
lease operation or the salability of certain types of coal;
(v) If a reasonable value cannot be determined using paragraphs
(c)(2)(i), (ii), (iii), or (iv) of this section, then a net-back method
or any other reasonable method shall be used to determine value.
(3) When the value of coal is determined pursuant to paragraph
(c)(2) of this section, that value determination shall be consistent
with the provisions contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of
this section, that value does not require ONRR's prior approval.
However, the lessee shall retain all data relevant to the determination
of royalty value. Such data shall be subject to review and audit, and
ONRR will direct a lessee to use a different value if it determines
that the reported value is inconsistent with the requirements of these
regulations.
[[Page 36984]]
(2) An Indian lessee will make available upon request to the
authorized ONRR or Indian representatives, or to the Inspector General
of the Department of the Interior or other persons authorized to
receive such information, arm's-length sales and sales quantity data
for like-quality coal sold, purchased, or otherwise obtained by the
lessee from the area.
(3) A lessee shall notify ONRR if it has determined value pursuant
to paragraphs (c)(2)(ii), (iii), (iv), or (v) of this section. The
notification shall be by letter to the Director for Office of Natural
Resources Revenue or his/her designee. The letter shall identify the
valuation method to be used and contain a brief description of the
procedure to be followed. The notification required by this section is
a one-time notification due no later than the month the lessee first
reports royalties on the form ONRR-4430 using a valuation method
authorized by paragraphs (c)(2)(ii), (iii), (iv), or (v) of this
section, and each time there is a change in a method under paragraphs
(c)(2)(iv) or (v) of this section.
(e) If ONRR determines that a lessee has not properly determined
value, the lessee shall be liable for the difference, if any, between
royalty payments made based upon the value it has used and the royalty
payments that are due based upon the value established by ONRR. The
lessee shall also be liable for interest computed pursuant to 30 CFR
1218.202. If the lessee is entitled to a credit, ONRR will provide
instructions for the taking of that credit.
(f) The lessee may request a value determination from ONRR. In that
event, the lessee shall propose to ONRR a value determination method,
and may use that method in determining value for royalty purposes until
ONRR issues its decision. The lessee shall submit all available data
relevant to its proposal. ONRR shall expeditiously determine the value
based upon the lessee's proposal and any additional information ONRR
deems necessary. That determination shall remain effective for the
period stated therein. After ONRR issues its determination, the lessee
shall make the adjustments in accordance with paragraph (e) of this
section.
(g) Notwithstanding any other provisions of this section, under no
circumstances shall the value for royalty purposes be less than the
gross proceeds accruing to the lessee for the disposition of produced
coal less applicable provisions of paragraph (b)(5) of this section and
less applicable allowances determined pursuant to Sec. Sec.
[thinsp]1206.457 through 1206.461 and[thinsp]1206.464 of this subpart.
(h) The lessee is required to place coal in marketable condition at
no cost to the Indian lessor. Where the value established pursuant to
this section is determined by a lessee's gross proceeds, that value
shall be increased to the extent that the gross proceeds has been
reduced because the purchaser, or any other person, is providing
certain services, the cost of which ordinarily is the responsibility of
the lessee to place the coal in marketable condition.
(i) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled, it
must pay royalty at a value based upon that obtainable price or
benefit. Contract revisions or amendments shall be in writing and
signed by all parties to an arm's-length contract, and may be
retroactively applied to value for royalty purposes for a period not to
exceed two years, unless ONRR approves a longer period. If the lessee
makes timely application for a price increase allowed under its
contract but the purchaser refuses, and the lessee takes reasonable
measures, which are documented, to force purchaser compliance, the
lessee will owe no additional royalties unless or until monies or
consideration resulting from the price increase are received. This
paragraph shall not be construed to permit a lessee to avoid its
royalty payment obligation in situations where a purchaser fails to
pay, in whole or in part or timely, for a quantity of coal.
(j) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by ONRR of value under this section
shall be considered final or binding as against the Indian Tribes or
allottees until the audit period is formally closed.
(k) Certain information submitted to ONRR to support valuation
proposals, including transportation, coal washing, or other allowances
pursuant to Sec. Sec. [thinsp]1206.457 through 1206.461 and 1206.464
of this subpart, is exempted from disclosure by the Freedom of
Information Act, 5 U.S.C. 522. Any data specified by the Act to be
privileged, confidential, or otherwise exempt shall be maintained in a
confidential manner in accordance with applicable law and regulations.
All requests for information about determinations made under this part
are to be submitted in accordance with the Freedom of Information Act
regulation of the Department of the Interior, 43 CFR part 2. Nothing in
this section is intended to limit or diminish in any manner whatsoever
the right of an Indian lessor to obtain any and all information as such
lessor may be lawfully entitled from ONRR or such lessor's lessee
directly under the terms of the lease or applicable law.
Sec. [thinsp]1206.457 Washing allowances--general.
(a) For ad valorem leases subject to Sec. [thinsp]1206.456 of this
subpart, ONRR shall, as authorized by this section, allow a deduction
in determining value for royalty purposes for the reasonable, actual
costs incurred to wash coal, unless the value determined pursuant to
Sec. [thinsp]1206.456 of this subpart was based upon like-quality
unwashed coal. Under no circumstances will the authorized washing
allowance and the transportation allowance reduce the value for royalty
purposes to zero.
(b) If ONRR determines that a lessee has improperly determined a
washing allowance authorized by this section, then the lessee shall be
liable for any additional royalties, plus interest determined in
accordance with Sec. [thinsp]1218.202 of this chapter, or shall be
entitled to a credit, without interest.
(c) Lessees shall not disproportionately allocate washing costs to
Indian leases.
(d) No cost normally associated with mining operations and which
are necessary for placing coal in marketable condition shall be allowed
as a cost of washing.
(e) Coal washing costs shall only be recognized as allowances when
the washed coal is sold and royalties are reported and paid.
Sec. [thinsp]1206.458 Determination of washing allowances.
(a) Arm's-length contracts. (1) For washing costs incurred by a
lessee pursuant to an arm's-length contract, the washing allowance
shall be the reasonable actual costs incurred by the lessee for washing
the coal under that contract, subject to monitoring, review, audit, and
possible future adjustment. ONRR's prior approval is not required
before a lessee may deduct costs incurred under an arm's-length
contract. However, before any deduction may be taken, the lessee must
submit a completed page one of form ONRR-4292, Coal Washing Allowance
Report, in accordance with paragraph (c)(1) of this section. A washing
allowance may be claimed retroactively for a period of not more than 3
months prior to the first day of the month that form ONRR-4292 is filed
with ONRR, unless ONRR approves a longer period upon a showing of good
cause by the lessee.
[[Page 36985]]
(2) In conducting reviews and audits, ONRR will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the washer for the
washing. If the contract reflects more than the total consideration
paid, then ONRR may require that the washing allowance be determined in
accordance with paragraph (b) of this section.
(3) If ONRR determines that the consideration paid pursuant to an
arm's-length washing contract does not reflect the reasonable value of
the washing because of misconduct by or between the contracting
parties, or because the lessee otherwise has breached its duty to the
lessor to market the production for the mutual benefit of the lessee
and the lessor, then ONRR shall require that the washing allowance be
determined in accordance with paragraph (b) of this section. When ONRR
determines that the value of the washing may be unreasonable, ONRR will
notify the lessee and give the lessee an opportunity to provide written
information justifying the lessee's washing costs.
(4) Where the lessee's payments for washing under an arm's-length
contract are not based on a dollar-per-unit basis, the lessee shall
convert whatever consideration is paid to a dollar value equivalent.
Washing allowances shall be expressed as a cost per ton of coal washed.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations
where the lessee performs washing for itself, the washing allowance
will be based upon the lessee's reasonable actual costs. All washing
allowances deducted under a non-arm's-length or no contract situation
are subject to monitoring, review, audit, and possible future
adjustment. Prior ONRR approval of washing allowances is not required
for non-arm's-length or no contract situations. However, before any
estimated or actual deduction may be taken, the lessee must submit a
completed form ONRR-4292 in accordance with paragraph (c)(2) of this
section. A washing allowance may be claimed retroactively for a period
of not more than 3 months prior to the first day of the month that form
ONRR-4292 is filed with ONRR, unless ONRR approves a longer period upon
a showing of good cause by the lessee. ONRR will monitor the allowance
deduction to ensure that deductions are reasonable and allowable. When
necessary or appropriate, ONRR may direct a lessee to modify its actual
washing allowance.
(2) The washing allowance for non-arm's-length or no contract
situations shall be based upon the lessee's actual costs for washing
during the reported period, including operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable
investment in the wash plant multiplied by the rate of return in
accordance with paragraph (b)(2)(iv)(B) of this section. Allowable
capital costs are generally those for depreciable fixed assets
(including costs of delivery and installation of capital equipment)
which are an integral part of the wash plant.
(i) Allowable operating expenses include: Operations supervision
and engineering; operations labor; fuel; utilities; materials; ad
valorem property taxes; rent; supplies; and any other directly
allocable and attributable operating expense which the lessee can
document.
(ii) Allowable maintenance expenses include: Maintenance of the
wash plant; maintenance of equipment; maintenance labor; and other
directly allocable and attributable maintenance expenses which the
lessee can document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the wash plant is an allowable expense. State and
Federal income taxes and severance taxes, including royalties, are not
allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this
section. After a lessee has elected to use either method for a wash
plant, the lessee may not later elect to change to the other
alternative without approval of ONRR.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the wash plant services, whichever is
appropriate, or a unit of production method. After an election is made,
the lessee may not change methods without ONRR approval. A change in
ownership of a wash plant shall not alter the depreciation schedule
established by the original operator/lessee for purposes of the
allowance calculation. With or without a change in ownership, a wash
plant shall be depreciated only once. Equipment shall not be
depreciated below a reasonable salvage value.
(B) ONRR shall allow as a cost an amount equal to the allowable
capital investment in the wash plant multiplied by the rate of return
determined pursuant to paragraph (b)(2)(v) of this section. No
allowance shall be provided for depreciation. This alternative shall
apply only to plants first placed in service or acquired after March 1,
1989.
(v) The rate of return shall be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return shall be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month of the reporting period for which the allowance is
applicable and shall be effective during the reporting period. The rate
shall be redetermined at the beginning of each subsequent washing
allowance reporting period (which is determined pursuant to paragraph
(c)(2) of this section).
(3) The washing allowance for coal shall be determined based on the
lessee's reasonable and actual cost of washing the coal. The lessee may
not take an allowance for the costs of washing lease production that is
not royalty bearing.
(c) Reporting requirements--(1) Arm's-length contracts. (i) With
the exception of those washing allowances specified in paragraphs
(c)(1)(v) and (vi) of this section, the lessee shall submit page one of
the initial form ONRR-4292 prior to, or at the same time, as the
washing allowance determined pursuant to an arm's-length contract is
reported on form ONRR-4430, Solid Minerals Production and Royalty
Report. A form ONRR-4292 received by the end of the month that the form
ONRR-4430 is due shall be considered to be received timely.
(ii) The initial form ONRR-4292 shall be effective for a reporting
period beginning the month that the lessee is first authorized to
deduct a washing allowance and shall continue until the end of the
calendar year, or until the applicable contract or rate terminates or
is modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding
reporting periods, lessees must submit page one of form ONRR-4292
within 3 months after the end of the calendar year, or after the
applicable contract or rate terminates or is modified or amended,
whichever is earlier, unless ONRR approves a longer period (during
which period the lessee shall continue to use the allowance from the
previous reporting period).
(iv) ONRR may require that a lessee submit arm's-length washing
contracts and related documents. Documents shall be submitted within a
reasonable time, as determined by ONRR.
(v) Washing allowances which are based on arm's-length contracts
and
[[Page 36986]]
which are in effect at the time these regulations become effective will
be allowed to continue until such allowances terminate. For the
purposes of this section, only those allowances that have been approved
by ONRR in writing shall qualify as being in effect at the time these
regulations become effective.
(vi) ONRR may establish, in appropriate circumstances, reporting
requirements that are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of
those washing allowances specified in paragraphs (c)(2)(v) and (vii) of
this section, the lessee shall submit an initial form ONRR-4292 prior
to, or at the same time as, the washing allowance determined pursuant
to a non-arm's-length contract or no contract situation is reported on
form ONRR-4430, Solid Minerals Production and Royalty Report. A form
ONRR-4292 received by the end of the month that the form ONRR-4430 is
due shall be considered to be timely received. The initial reporting
may be based on estimated costs.
(ii) The initial form ONRR-4292 shall be effective for a reporting
period beginning the month that the lessee first is authorized to
deduct a washing allowance and shall continue until the end of the
calendar year, or until the washing under the non-arm's-length contract
or the no contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial
reporting period, the lessee shall submit a completed form ONRR-4292
containing the actual costs for the previous reporting period. If coal
washing is continuing, the lessee shall include on form ONRR-4292 its
estimated costs for the next calendar year. The estimated coal washing
allowance shall be based on the actual costs for the previous period
plus or minus any adjustments which are based on the lessee's knowledge
of decreases or increases which will affect the allowance. Form ONRR-
4292 must be received by ONRR within 3 months after the end of the
previous reporting period, unless ONRR approves a longer period (during
which period the lessee shall continue to use the allowance from the
previous reporting period).
(iv) For new wash plants, the lessee's initial form ONRR-4292 shall
include estimates of the allowable coal washing costs for the
applicable period. Cost estimates shall be based upon the most recently
available operations data for the plant, or if such data are not
available, the lessee shall use estimates based upon industry data for
similar coal wash plants.
(v) Washing allowances based on non-arm's-length or no contract
situations which are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For the purposes of this section, only those allowances that have been
approved by ONRR in writing shall qualify as being in effect at the
time these regulations become effective.
(vi) Upon request by ONRR, the lessee shall submit all data used by
the lessee to prepare its forms ONRR-4292. The data shall be provided
within a reasonable period of time, as determined by ONRR.
(vii) ONRR may establish, in appropriate circumstances, reporting
requirements which are different from the requirements of this section.
(3) ONRR may establish coal washing allowance reporting dates for
individual leases different from those specified in this subpart in
order to provide more effective administration. Lessees will be
notified of any change in their reporting period.
(4) Washing allowances must be reported as a separate line on the
form ONRR-4430, unless ONRR approves a different reporting procedure.
(d) Interest assessments for incorrect or late reports and failure
to report. (1) If a lessee deducts a washing allowance on its form
ONRR-4430 without complying with the requirements of this section, the
lessee shall be liable for interest on the amount of such deduction
until the requirements of this section are complied with. The lessee
also shall repay the amount of any allowance which is disallowed by
this section.
(2) If a lessee erroneously reports a washing allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(3) Interest required to be paid by this section shall be
determined in accordance with Sec. [thinsp]1218.202 of this chapter.
(e) Adjustments. (1) If the actual coal washing allowance is less
than the amount the lessee has taken on form ONRR-4430 for each month
during the allowance form reporting period, the lessee shall be
required to pay additional royalties due plus interest computed
pursuant to Sec. [thinsp]1218.202, retroactive to the first month the
lessee is authorized to deduct a washing allowance. If the actual
washing allowance is greater than the amount the lessee has estimated
and taken during the reporting period, the lessee shall be entitled to
a credit, without interest.
(2) The lessee must submit a corrected form ONRR-4430 to reflect
actual costs, together with any payment, in accordance with
instructions provided by ONRR.
(f) Other washing cost determinations. The provisions of this
section shall apply to determine washing costs when establishing value
using a net-back valuation procedure or any other procedure that
requires deduction of washing costs.
Sec. [thinsp]1206.459 Allocation of washed coal.
(a) When coal is subjected to washing, the washed coal must be
allocated to the leases from which it was extracted.
(b) When the net output of coal from a washing plant is derived
from coal obtained from only one lease, the quantity of washed coal
allocable to the lease will be based on the net output of the washing
plant.
(c) When the net output of coal from a washing plant is derived
from coal obtained from more than one lease, unless determined
otherwise by BLM, the quantity of net output of washed coal allocable
to each lease will be based on the ratio of measured quantities of coal
delivered to the washing plant and washed from each lease compared to
the total measured quantities of coal delivered to the washing plant
and washed.
Sec. [thinsp]1206.460 Transportation allowances--general.
(a) For ad valorem leases subject to Sec. [thinsp]1206.456 of this
subpart, where the value for royalty purposes has been determined at a
point remote from the lease or mine, ONRR shall, as authorized by this
section, allow a deduction in determining value for royalty purposes
for the reasonable, actual costs incurred to:
(1) Transport the coal from an Indian lease to a sales point which
is remote from both the lease and mine; or
(2) 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. In-mine transportation
costs shall not be included in the transportation allowance.
(b) Under no circumstances will the authorized washing allowance
and the transportation allowance reduce the value for royalty purposes
to zero.
(c)(1) When coal transported from a mine to a wash plant is
eligible for a transportation allowance in accordance with this
section, the lessee is not required to allocate transportation costs
[[Page 36987]]
between the quantity of clean coal output and the rejected waste
material. The transportation allowance shall be authorized for the
total production which is transported. Transportation allowances shall
be expressed as a cost per ton of cleaned coal transported.
(2) For coal that is not washed at a wash plant, the transportation
allowance shall be authorized for the total production which is
transported. Transportation allowances shall be expressed as a cost per
ton of coal transported.
(3) Transportation costs shall only be recognized as allowances
when the transported coal is sold and royalties are reported and paid.
(d) If, after a review and/or audit, ONRR determines that a lessee
has improperly determined a transportation allowance authorized by this
section, then the lessee shall pay any additional royalties, plus
interest, determined in accordance with Sec. [thinsp]1218.202 of this
chapter, or shall be entitled to a credit, without interest.
(e) Lessees shall not disproportionately allocate transportation
costs to Indian leases.
Sec. [thinsp]1206.461 Determination of transportation allowances.
(a) Arm's-length contracts. (1) For transportation costs incurred
by a lessee pursuant to an arm's-length contract, the transportation
allowance shall be the reasonable, actual costs incurred by the lessee
for transporting the coal under that contract, subject to monitoring,
review, audit, and possible future adjustment. ONRR's prior approval is
not required before a lessee may deduct costs incurred under an arm's-
length contract. However, before any deduction may be taken, the lessee
must submit a completed page one of form ONRR-4293, Coal Transportation
Allowance Report, in accordance with paragraph (c)(1) of this section.
A transportation allowance may be claimed retroactively for a period of
not more than 3 months prior to the first day of the month that form
ONRR-4293 is filed with ONRR, unless ONRR approves a longer period upon
a showing of good cause by the lessee.
(2) In conducting reviews and audits, ONRR will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the transporter for
the transportation. If the contract reflects more than the total
consideration paid, then ONRR may require that the transportation
allowance be determined in accordance with paragraph (b) of this
section.
(3) If ONRR determines that the consideration paid pursuant to an
arm's-length transportation contract does not reflect the reasonable
value of the transportation because of misconduct by or between the
contracting parties, or because the lessee otherwise has breached its
duty to the lessor to market the production for the mutual benefit of
the lessee and the lessor, then ONRR shall require that the
transportation allowance be determined in accordance with paragraph (b)
of this section. When ONRR determines that the value of the
transportation may be unreasonable, ONRR will notify the lessee and
give the lessee an opportunity to provide written information
justifying the lessee's transportation costs.
(4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar-per-unit basis, the lessee
shall convert whatever consideration is paid to a dollar value
equivalent for the purposes of this section.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations
where the lessee performs transportation services for itself, the
transportation allowance will be based upon the lessee's reasonable
actual costs. All transportation allowances deducted under a non-arm's-
length or no contract situation are subject to monitoring, review,
audit, and possible future adjustment. Prior ONRR approval of
transportation allowances is not required for non-arm's-length or no
contract situations. However, before any estimated or actual deduction
may be taken, the lessee must submit a completed form ONRR-4293 in
accordance with paragraph (c)(2) of this section. A transportation
allowance may be claimed retroactively for a period of not more than 3
months prior to the first day of the month that form ONRR-4293 is filed
with ONRR, unless ONRR approves a longer period upon a showing of good
cause by the lessee. ONRR will monitor the allowance deductions to
ensure that deductions are reasonable and allowable. When necessary or
appropriate, ONRR may direct a lessee to modify its estimated or actual
transportation allowance deduction.
(2) The transportation allowance for non-arm's-length or no
contract situations shall be based upon the lessee's actual costs for
transportation during the reporting period, including operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable
investment in the transportation system multiplied by the rate of
return in accordance with paragraph (b)(2)(iv)(B) of this section.
Allowable capital costs are generally those for depreciable fixed
assets (including costs of delivery and installation of capital
equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision
and engineering; operations labor; fuel; utilities; materials; ad
valorem property taxes; rent; supplies; and any other directly
allocable and attributable operating expense which the lessee can
document.
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which
the lessee can document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the transportation system is an allowable expense. State
and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this
section. After a lessee has elected to use either method for a
transportation system, the lessee may not later elect to change to the
other alternative without approval of ONRR.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services,
whichever is appropriate, or a unit of production method. After an
election is made, the lessee may not change methods without ONRR
approval. A change in ownership of a transportation system shall not
alter the depreciation schedule established by the original
transporter/lessee for purposes of the allowance calculation. With or
without a change in ownership, a transportation system shall be
depreciated only once. Equipment shall not be depreciated below a
reasonable salvage value.
(B) ONRR shall allow as a cost an amount equal to the allowable
capital investment in the transportation system multiplied by the rate
of return determined pursuant to paragraph (b)(2)(B)(v) of this
section. No allowance shall be provided for depreciation. This
alternative shall apply only to transportation facilities first placed
in service or acquired after March 1, 1989.
[[Page 36988]]
(v) The rate of return shall be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return shall be the monthly
average as published in Standard and Poor's Bond Guide for the first
month of the reporting period of which the allowance is applicable and
shall be effective during the reporting period. The rate shall be
redetermined at the beginning of each subsequent transportation
allowance reporting period (which is determined pursuant to paragraph
(c)(2) of this section).
(3) A lessee may apply to ONRR for exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1) and
(2) of this section. ONRR will grant the exception only if the lessee
has a rate for the transportation approved by a Federal agency for
Indian leases. ONRR shall deny the exception request if it determines
that the rate is excessive as compared to arm's-length transportation
charges by systems, owned by the lessee or others, providing similar
transportation services in that area. If there are no arm's-length
transportation charges, ONRR shall deny the exception request if:
(i) No Federal regulatory agency cost analysis exists and the
Federal regulatory agency has declined to investigate pursuant to ONRR
timely objections upon filing; and
(ii) The rate significantly exceeds the lessee's actual costs for
transportation as determined under this section.
(c) Reporting requirements--(1) Arm's-length contracts. (i) With
the exception of those transportation allowances specified in
paragraphs (c)(1)(v) and (vi) of this section, the lessee shall submit
page one of the initial form ONRR-4293 prior to, or at the same time
as, the transportation allowance determined pursuant to an arm's-length
contract is reported on form ONRR-4430, Solid Minerals Production and
Royalty Report.
(ii) The initial form ONRR-4293 shall be effective for a reporting
period beginning the month that the lessee is first authorized to
deduct a transportation allowance and shall continue until the end of
the calendar year, or until the applicable contract or rate terminates
or is modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding
reporting periods, lessees must submit page one of form ONRR-4293
within 3 months after the end of the calendar year, or after the
applicable contract or rate terminates or is modified or amended,
whichever is earlier, unless ONRR approves a longer period (during
which period the lessee shall continue to use the allowance from the
previous reporting period). Lessees may request special reporting
procedures in unique allowance reporting situations, such as those
related to spot sales.
(iv) ONRR may require that a lessee submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents. Documents shall be submitted within a reasonable
time, as determined by ONRR.
(v) Transportation allowances that are based on arm's-length
contracts and which are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For the purposes of this section, only those allowances that have been
approved by ONRR in writing shall qualify as being in effect at the
time these regulations become effective.
(vi) ONRR may establish, in appropriate circumstances, reporting
requirements that are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of
those transportation allowances specified in paragraphs (c)(2)(v) and
(vii) of this section, the lessee shall submit an initial form ONRR-
4293 prior to, or at the same time as, the transportation allowance
determined pursuant to a non-arm's-length contract or no contract
situation is reported on form ONRR-4430, Solid Minerals Production and
Royalty Report. The initial report may be based on estimated costs.
(ii) The initial form ONRR-4293 shall be effective for a reporting
period beginning the month that the lessee first is authorized to
deduct a transportation allowance and shall continue until the end of
the calendar year, or until the transportation under the non-arm's-
length contract or the no contract situation terminates, whichever is
earlier.
(iii) For calendar-year reporting periods succeeding the initial
reporting period, the lessee shall submit a completed form ONRR-4293
containing the actual costs for the previous reporting period. If the
transportation is continuing, the lessee shall include on form ONRR-
4293 its estimated costs for the next calendar year. The estimated
transportation allowance shall be based on the actual costs for the
previous reporting period plus or minus any adjustments that are based
on the lessee's knowledge of decreases or increases that will affect
the allowance. form ONRR-4293 must be received by ONRR within 3 months
after the end of the previous reporting period, unless ONRR approves a
longer period (during which period the lessee shall continue to use the
allowance from the previous reporting period).
(iv) For new transportation facilities or arrangements, the
lessee's initial form ONRR-4293 shall include estimates of the
allowable transportation costs for the applicable period. Cost
estimates shall be based upon the most recently available operations
data for the transportation system, or, if such data are not available,
the lessee shall use estimates based upon industry data for similar
transportation systems.
(v) Non-arm's-length contract or no contract-based transportation
allowances that are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For purposes of this section, only those allowances that have been
approved by ONRR in writing shall qualify as being in effect at the
time these regulations become effective.
(vi) Upon request by ONRR, the lessee shall submit all data used to
prepare its form ONRR-4293. The data shall be provided within a
reasonable period of time, as determined by ONRR.
(vii) ONRR may establish, in appropriate circumstances, reporting
requirements that are different from the requirements of this section.
(viii) If the lessee is authorized to use its Federal-agency-
approved rate as its transportation cost in accordance with paragraph
(b)(3) of this section, it shall follow the reporting requirements of
paragraph (c)(1) of this section.
(3) ONRR may establish reporting dates for individual lessees
different than those specified in this paragraph in order to provide
more effective administration. Lessees will be notified as to any
change in their reporting period.
(4) Transportation allowances must be reported as a separate line
item on form ONRR-4430, unless ONRR approves a different reporting
procedure.
(d) Interest assessments for incorrect or late reports and failure
to report. (1) If a lessee deducts a transportation allowance on its
form ONRR-4430 without complying with the requirements of this section,
the lessee shall be liable for interest on the amount of such deduction
until the requirements of this section are complied with. The lessee
also shall repay the amount of any allowance which is disallowed by
this section.
(2) If a lessee erroneously reports a transportation allowance
which results in an underpayment of royalties, interest shall be paid
on the amount of that underpayment.
[[Page 36989]]
(3) Interest required to be paid by this section shall be
determined in accordance with Sec. [thinsp]1218.202 of this chapter.
(e) Adjustments. (1) If the actual transportation allowance is less
than the amount the lessee has taken on form ONRR-4430 for each month
during the allowance form reporting period, the lessee shall be
required to pay additional royalties due plus interest, computed
pursuant to Sec. [thinsp]1218.202 of this chapter, retroactive to the
first month the lessee is authorized to deduct a transportation
allowance. If the actual transportation allowance is greater than the
amount the lessee has estimated and taken during the reporting period,
the lessee shall be entitled to a credit, without interest.
(2) The lessee must submit a corrected form ONRR-4430 to reflect
actual costs, together with any payment, in accordance with
instructions provided by ONRR.
(f) Other transportation cost determinations. The provisions of
this section shall apply to determine transportation costs when
establishing value using a net-back valuation procedure or any other
procedure that requires deduction of transportation costs.
Sec. [thinsp]1206.462 [Reserved]
Sec. [thinsp]1206.463 In-situ and surface gasification and
liquefaction operations.
If an ad valorem Federal coal lease is developed by in-situ or
surface gasification or liquefaction technology, the lessee shall
propose the value of coal for royalty purposes to ONRR. ONRR will
review the lessee's proposal and issue a value determination. The
lessee may use its proposed value until ONRR issues a value
determination.
Sec. [thinsp]1206.464 Value enhancement of marketable coal.
If, prior to use, sale, or other disposition, the lessee enhances
the value of coal after the coal has been placed in marketable
condition in accordance with Sec. [thinsp]1206.456(h) of this subpart,
the lessee shall notify ONRR that such processing is occurring or will
occur. The value of that production shall be determined as follows:
(a) A value established for the feedstock coal in marketable
condition by application of the provisions of Sec.
[thinsp]1206.456(c)(2)(i) through (iv) of this subpart; or,
(b) In the event that a value cannot be established in accordance
with paragraph (a) of this section, then the value of production will
be determined in accordance with Sec. [thinsp]1206.456(c)(2)(v) of
this subpart and the value shall be the lessee's gross proceeds
accruing from the disposition of the enhanced product, reduced by ONRR-
approved processing costs and procedures including a rate of return on
investment equal to two times the Standard and Poor's BBB bond rate
applicable under Sec. [thinsp]1206.458(b)(2)(v) of this subpart.
[FR Doc. 2017-16571 Filed 8-4-17; 8:45 am]
BILLING CODE 4335-30-P
