ONRR 2020 Valuation Reform and Civil Penalty Rule

 
CONTENT
Federal Register, Volume 85 Issue 191 (Thursday, October 1, 2020)
[Federal Register Volume 85, Number 191 (Thursday, October 1, 2020)]
[Proposed Rules]
[Pages 62054-62092]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-17513]
[[Page 62053]]
Vol. 85
Thursday,
No. 191
October 1, 2020
Part III
Department of the Interior
-----------------------------------------------------------------------
Office of Natural Resources Revenue
-----------------------------------------------------------------------
30 CFR Parts 1206 and 1241
ONRR 2020 Valuation Reform and Civil Penalty Rule; Proposed Rule
Federal Register / Vol. 85 , No. 191 / Thursday, October 1, 2020 /
Proposed Rules
[[Page 62054]]
-----------------------------------------------------------------------
DEPARTMENT OF THE INTERIOR
Office of Natural Resources Revenue
30 CFR Parts 1206 and 1241
[Docket No. ONRR-2020-0001; DS63644000 DRT000000.CH7000 201D1113RT]
RIN 1012-AA27
ONRR 2020 Valuation Reform and Civil Penalty Rule
AGENCY: Department of the Interior, Office of the Secretary, Office of
Natural Resources Revenue.
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: The Office of Natural Resources Revenue (``ONRR'') is
publishing this proposed rule to seek comment on measures to amend
portions of ONRR's regulations for valuing oil and gas produced from
Federal leases for royalty purposes, valuing coal produced from Federal
and Indian leases, and assessing civil penalties for violations of
certain statutes, regulations, leases, and orders associated with
mineral leases.
DATES: You must submit comments on or before November 30, 2020.
ADDRESSES: You may submit comments to ONRR using any of the following
three methods. Please reference Regulation Identifier Number (RIN)
1012-AA27 in any comment:
 Electronically submit at http://www.regulations.gov. In
the search bar titled ``SEARCH for: Rules, Comments, Adjudications or
Supporting Documents:'' enter ``ONRR-2020-0001,'' and then click
``Search.'' Follow the instructions to submit public comments.
 Email comments to Dane Templin, Regulations Supervisor, at
[email protected] and Luis Aguilar, Regulatory Specialist, at
[email protected]. Include RIN 1012-AA27 in the subject line of the
message.
 Hand-carry or mail comments to the Office of Natural
Resources Revenue, Building 85, Entrance N-1, Denver Federal Center,
West 6th Ave. and Kipling St., Denver, Colorado 80225.
 Instructions: All comments must include the agency name and docket
number or RIN for this rulemaking. All comments, including any personal
identifying information or confidential business information contained
in a comment, will be posted without change to https://www.onrr.gov/Laws_R_D/FRNotices/AA27.htm. See also Public Availability of Comments
under the Procedural Matters section of this document.
 Docket: For access to the docket to read background documents or
comments received, go to https://regulations.gov or https://www.onrr.gov/Laws_R_D/FRNotices/AA27.htm.
FOR FURTHER INFORMATION CONTACT: For questions on procedural issues,
contact Dane Templin at (303) 231-3149, or by email addressed to
[email protected]. For comments or questions on technical issues,
contact Amy Lunt, Supervisor Royalty Valuation Team A, at (303) 231-
3746, or by email addressed to [email protected], or Peter Christnacht,
Supervisor Royalty Valuation Team B, at (303) 231-3651, or by email
addressed to [email protected].
SUPPLEMENTARY INFORMATION:
I. Executive Summary
 ONRR is proposing, for multiple reasons, targeted amendments to 30
CFR part 1206 (most recently amended by the 2016 Consolidated Federal
Oil & Gas and Federal & Indian Coal Valuation Reform Rule (``2016
Valuation Rule'')). First, the 2016 Valuation Rule added certain
provisions that are inconsistent with multiple executive orders that
have been issued after the 2016 Valuation Rule's effective date,
including Executive Order on Promoting Energy Independence and Economic
Growth (Executive Order 13783), which directs agencies to ``identify
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.'' Second, ONRR, after
defending its amendments to the Federal and Indian coal valuation rules
in 2016 Valuation Rule litigation, and upon consideration of the
parties' briefs and receiving the Court's ruling, has determined that
it should propose a revision to the most controversial coal valuation
rules. Third, the proposed amendments would update ONRR's regulations
to simplify certain processes, provide early clarity regarding
royalties owed, and better explain ONRR's civil penalty practices.
Finally, this proposed rule would return the relationship between the
Federal government, States, Tribes, and regulated parties to the
longstanding and familiar valuation framework that existed under FOGRMA
for many years prior to the 2016 Valuation Rule. The agency finds that
these reasons, collectively and individually, warrant amending ONRR's
valuation and civil penalty regulations.
 In addition, ONRR proposes to amend 30 CFR part 1241 (most recently
amended by the 2016 Amendments to Civil Penalty Regulations (``2016
Civil Penalty Rule'')) to conform that part with a decision recently
issued by a federal district court and to clarify that the 2016 Civil
Penalty Rule conforms with ONRR's long-standing practice.
 ONRR believes that regulatory certainty will be best served by
amending targeted portions of 30 CFR part 1206 that the 2016 Valuation
Rule also addressed, including recodifying certain pre-2017 regulations
to achieve a more rational balance between the government's interest in
effective regulation of royalties and the burden on the regulated
entities. Though ONRR recognizes that the regulations in place prior to
the 2016 Valuation Rule pose certain implementation challenges, the
agency finds that restoring those prior regulations is preferable to
maintaining ONRR's rules, as modified by 2016 Valuation Rule, because
returning to some of the prior regulations would reinstate a
longstanding, nationwide regulatory framework that is better understood
by the parties interpreting and applying the regulations (ONRR and the
regulated entities). The proposed rule would also meet policy
objectives stated in certain Executive Orders, including Executive
Order 13783, ``Promoting Energy Independence and Economic Growth,''
Executive Order 13795, ``Implementing an America-First Offshore Energy
Strategy,'' and would support Secretarial Order 3350, which promotes
the America-First Offshore Energy Strategy.
 In July 2016, ONRR published the 2016 Valuation Rule, amending, in
a number of significant respects, the valuation regulations applicable
to Federal oil and gas and Federal and Indian coal. 81 FR 43338, July
1, 2016 (https://www.onrr.gov/Laws_R_D/FRNotices/AA13.htm). The
effective date of the 2016 Valuation Rule was January 1, 2017. ONRR is
reissuing the 2016 Valuation Rule in the Rule and Regulations section
of this issue of the Federal Register.
 With respect to Federal oil and gas, this proposed rule would alter
or reverse some of the changes brought about by the 2016 Valuation Rule
in order to return to the definitions and practices that had been in
place since the 1980s. The proposed changes to return to historical
practices include: (1) Reinstating the ability of a lessee to request
to exceed the 50-percent regulatory limit for transportation costs; (2)
reinstating the ability of a lessee to
[[Page 62055]]
request to exceed the 66 2/3-percent regulatory limit for processing
costs; (3) allowing a lessee producing offshore to claim, without
requesting case-by-case approval, certain gathering costs as a
transportation allowance in waters 200 meters and deeper; (4) allowing
a lessee producing offshore to request ONRR's approval to claim certain
gathering costs as a transportation allowance in waters shallower than
200 meters where ``deepwater-like'' subsea movement occurs; (5)
removing the misconduct definition (also applies to Federal and Indian
coal); (6) removing the default provision and all references thereto
(also applies to Federal and Indian coal); (7) eliminating the
requirement that written contracts be signed by all parties (also
applies to Federal and Indian coal); and (8) eliminating the
requirement that companies cite legal precedent when seeking a
valuation determination (also applies to Federal and Indian coal). In
addition, this proposed rule would expand concepts first adopted in the
2016 Valuation Rule. The proposed expansion to those 2016 Valuation
Rule concepts includes extending the index-based valuation option to
all Federal gas dispositions. Finally, this proposed rule would change
a few index-based valuation concepts in the 2016 Valuation Rule,
including changing the index-based option for unprocessed and residue
gas from the highest bidweek price to an average bidweek price;
updating the index-based transportation deductions based on more
current data; expressly stating that a lessee cannot report royalty
values of zero or less; and, expressing that ONRR can request
production of a variety of records from lessees who report under an
index-based option.
 By reverting to certain pre-2016 Valuation Rule practices, this
rule would reintroduce one ONRR-quantified administrative cost that the
2016 Valuation Rule eliminated--accounting for deepwater gathering
costs that may be claimed as part of a transportation allowance.
Described further in Section E, ONRR estimates that Federal lessees
would incur an additional $3.136 million in administrative costs in
order to increase reported transportation allowances by $30.5 to $41.3
million per year related to deepwater gathering.
 With respect to Federal and Indian coal, this proposed rule would
eliminate some of the changes brought about by the 2016 Valuation Rule
in order to address deficiencies in the 2016 Valuation Rule identified
by the United States District Court for the District of Wyoming in
Cloud Peak Energy, Inc., v. U.S. Dep't of the Interior, 415 F. Supp. 3d
1034 (D. Wy. 2019). Specifically, this proposed rule would remove the
requirement that coal be valued based on sales of electricity and
eliminate the definition of coal cooperative.
 In August 2016, ONRR published the 2016 Civil Penalty Rule. 81 FR
50306, August 1, 2016 (https://www.onrr.gov/Laws_R_D/FRNotices/AA05.htm). This proposed rule would change the regulations to conform
to the decision issued in American Petroleum Institute (``API'') v.
U.S. Dep't of the Interior, 366 F. Supp. 3d 1292, 1309-10 (D. Wyo.
2018), by eliminating the Department's administrative law judges'
ability to reverse a stay of the accrual of civil penalties upon a
showing that the lessee's defense to a civil penalty notice was
``frivolous.'' In addition, this proposed rule would clarify ONRR's
long-standing practice with respect to aggravating and mitigating
circumstances, and the information that ONRR considers in assessing the
amount of a civil penalty to issue in a case involving violations of a
lessee's obligation to pay money to the United States (a ``payment
violation'').
A. ONRR's Prior Related Rulemaking and Associated Litigation
1. Federal Oil and Gas and Federal and Indian Coal
 Prior to January 1, 2017, the royalty valuation framework for
Federal oil and gas and Federal and Indian coal was based on
regulations published in 1988 and 1989. After ONRR published the 2016
Valuation Rule, several industry groups filed lawsuits to challenge the
2016 Valuation Rule in the U.S. District Court for the District of
Wyoming on December 29, 2016.
 On February 17, 2017, the petitioners requested that ONRR postpone
implementation of the 2016 Valuation Rule, and alleged that the rule
would create widespread uncertainty and render compliance impossible.
On February 27, 2017, ONRR published a Postponement Notice in the
Federal Register, 82 FR 11823. In response to the Postponement Notice,
California and New Mexico filed a lawsuit in the U.S. District Court
for the Northern Division of California that alleged ONRR's action
violated the Administrative Procedure Act (APA). The presiding
magistrate judge concluded that ONRR's postponement of the 2016
Valuation Rule violated the APA. See Becerra v. U.S. Dep't. of the
Interior, 276 F. Supp. 3d 953, 967 (N.D. Cal. 2017).
 On April 4, 2017, ONRR published a proposed rule in the Federal
Register to repeal the 2016 Valuation Rule in its entirety, 82 FR 16323
(https://www.onrr.gov/Laws_R_D/FRNotices/PDFDocs/16323.pdf). Then, on
August 7, 2017, ONRR published the Repeal of Consolidated Federal Oil &
Gas and Federal & Indian Coal Valuation Reform final rule, which
repealed the 2016 Valuation Rule in its entirety (``2017 Repeal
Rule''), 82 FR 36934 (https://www.onrr.gov/Laws_R_D/FRNotices/AA20.htm). In response to the repeal, industry dismissed the lawsuits
challenging the 2016 Valuation Rule and, on October 7, 2017, the States
of California and New Mexico filed litigation to challenge the 2017
Repeal Rule.
 On March 29, 2019, the United States District Court for the
Northern District of California issued a decision in the case filed by
the States of California and New Mexico, vacating ONRR's 2017 Repeal
Rule (``2019 Vacatur''). California, v. U.S. Dep't of the Interior, 381
F. Supp. 3d 1153 (N.D. Cal. 2019). The 2019 Vacatur reinstated the 2016
Valuation Rule, including its effective date of January 1, 2017. One of
the district court's findings in the case was that ONRR failed to
adequately explain the regulatory change.
 First, the district court held that ONRR did not provide a reasoned
explanation as to ``why the industry concerns [regarding compliance
issues with the 2016 Valuation Rule that ONRR] previously rejected--as
well as its prior findings in support of adopting the [2016 Valuation
Rule]--now justified returning to the pre-[2016 Valuation Rule]
regulatory framework. Nowhere in the Final Repeal does the ONRR provide
such an explanation.'' Id. at 1166 (citation omitted). The district
court went on to state that ``[a]lthough the ONRR is entitled to change
its position, it must provide `a reasoned explanation . . . for
disregarding facts and circumstances that underlay or were engendered
by the prior policy.''' Id. at 1168. ``ONRR's conclusory explanation in
the Final Repeal fails to satisfy its obligation to explain
inconsistencies between its prior findings in enacting the [2016
Valuation Rule] and its decision to repeal such Rule.'' Id.
 Second, the district court held that there was no support for
ONRR's complete repeal of the 2016 Valuation Rule. Id. ``When
considering revoking a rule, an agency must consider alternatives in
lieu of complete repeal, such as by addressing the deficiencies
individually.'' Id. The court found that such action was arbitrary and
capricious. Id. at 1169 (citing California v. Bureau of Land Mgmt., 286
F. Supp. 3d 1054, 1066-67 (N.D. Cal. 2018)
[[Page 62056]]
(finding that even if the agency had factual evidence to support its
claim that the new regulations at issue in that rule burdened small
operators, a ``blanket suspension'' of the regulations was arbitrary
and capricious because the suspension was ``not properly tailored'' to
address the allegedly defective provision)).
 Third, the district court found that ONRR's citation to Executive
Order 13783 as justification for repeal of the 2016 Valuation Rule was
not adequately explained and conclusory. Id. at 1169-70. ``More
fundamentally, the ONRR's speculation that provisions [in the 2016
Valuation Rule] would be unduly burdensome, difficult to apply and
increase costs, directly contradict its previous findings in its
promulgation of the [2016 Valuation Rule].'' Id. at 1170. The court
concluded that an agency's failure to provide a reasoned explanation
for its decision to suspend a rule based on the rule's costs, while
ignoring its benefits, violates the APA. Id.
 Fourth, the district court found that ONRR could not rely on
potential future findings and recommendations made by its Royalty
Policy Committee to justify repeal of the 2016 Valuation Rule, although
ONRR stated it was not, in any event, doing so. Id. at 1171.
``Predicating a repeal decision on recommendations that may or may not
occur in the future is arbitrary and capricious.'' Id.
 After ONRR reinstated the 2016 Valuation Rule, industry refiled
litigation challenging the 2016 Valuation Rule. That litigation is
currently proceeding in the United States District Court for the
District of Wyoming. Cloud Peak Energy, Inc. v. U.S. Dep't of the
Interior, Case No. 19-CV-120-SWS (D. Wyo.). On October 8, 2019, the
Wyoming District Court entered an Order granting in part and denying in
part industry's request for a preliminary injunction of the
implementation of the 2016 Valuation Rule. The Court refused to enjoin
the portions of the 2016 Valuation Rule applicable to Federal oil and
gas but stayed the portions of the 2016 Valuation Rule applicable to
Federal and Indian coal. Cloud Peak, 415 F. Supp. 3d at 1053. Thus, the
1989 Federal and Indian Coal Valuation Regulations continue to govern
coal valuation produced from Federal and Indian leases.
 Through two ``Dear Reporter'' letters (dated June 13, 2019, and
November 20, 2019), ONRR has provided reporters and payors until July
1, 2020, to comply with the portions of the 2016 Valuation Rule
applicable to Federal oil and gas (https://www.onrr.gov/PDFDocs/Dear-Reporter-Letter-2016-Rule.pdf and https://www.onrr.gov/PDFDocs/dear-reporter-letter-20-Nov-19.pdf).
2. Civil Penalties
 On August 1, 2016, the 2016 Civil Penalty Rule was published. 81 FR
50306 (https://www.onrr.gov/Laws_R_D/FRNotices/AA05.htm). In the API
case, supra, the 2016 Civil Penalty Rule withstood industry's
challenge, with the exception of the challenge to 30 CFR 1241.11(b)(5),
which related to the Department's administrative law judges' power to
stay civil penalty accruals pending appeal. 366 F. Supp. 3d at 1311.
API has appealed the District Judge's decision on the remaining
portions of the 2016 Civil Penalty Rule and that appeal is pending in
the United States Court of Appeals for the Tenth Circuit. API v. U.S.
Dep't of the Interior, Case No. 18-8070 (10th Cir.).
B. Rulemaking Objectives
 This rulemaking is not founded upon new factual findings
contradicting those upon which the 2016 Valuation Rule was based.
Instead, ONRR is implementing this rulemaking because policy directives
issued after July 1, 2016, give different weight to the factual
findings, and also dictate that a different policy-based outcome be
pursued.
 A revised rulemaking based on ``a reevaluation of which policy
would be better in light of the facts'' is ``well within an agency's
discretion.'' Nat'l Ass'n of Home Builders v. EPA, 682 F.3d 1032, 1038
(D.C. Cir. 2012) (citing FCC v. Fox Television Stations, Inc., 556 U.S.
502, 514-15 (2009)). Further, ``[a] change in administration brought
about by the people casting their votes is a perfectly reasonable basis
for an executive agency's reappraisal of the costs and benefits of its
programs and regulations.'' Id. at 1043 (quoting Motor Vehicle Mfrs.
Ass'n of the U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29,
59 (1983) (Rehnquist, J., concurring in part and dissenting in part)).
An ``agency is entitled to have second thoughts, and to sustain action
which it considers in the public interest upon whatever basis more
mature reflection suggests.'' Dana Corp. v. ICC, 703 F.2d 1297, 1305
(D.C. Cir. 1983). An agency is entitled to give more weight to
socioeconomic concerns than it may have under a different
administration. Organized Vill. of Kake v. U.S. Dep't. of Agric., 795
F.3d 956, 968 (9th Cir. 2015) (en banc).
 In determining that ONRR should reconsider its rules, it considered
Executive Order 13783, ``Promoting Energy Independence and Economic
Growth;'' Executive Order 13795, ``Implementing an America-First
Offshore Energy Strategy;'' and Secretarial Orders 3350 and 3360, which
promote the America-First Offshore Energy Strategy and require a review
of regulations that ``potentially burden the development or utilization
of domestically produced energy resources,'' respectively. These
Executive and Secretarial Orders directed review of various agency
actions, without directing specific outcomes for rulemakings.
1. Executive Order 13783, Promoting Energy Independence and Economic
Growth, March 28, 2017
 In Executive Order 13783, the President emphasized 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 President
further directed executive departments and agencies to 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. Pursuant to Executive
Order 13783, agency heads are required to review all existing
regulations that potentially burden the development or use of
domestically produced energy resources, ``with particular attention to
oil, natural gas, coal, and nuclear energy resources.'' Executive Order
13783 further explained that ``burden'' means to unnecessarily
obstruct, delay, curtail, or otherwise impose significant costs on the
siting, permitting, production, utilization, transmission, or delivery
of energy resources.
2. Executive Order 13795, Implementing an America-First Offshore Energy
Strategy, April 28, 2017
 Through Executive Order 13795, the President stated his policy goal
of emphasizing ``the energy needs of American families and businesses
first'' and to ``continue implementing a plan that ensures energy
security and economic vitality for decades to come.'' The Executive
Order 13795 stated that ``[i]ncreased domestic energy production on
Federal lands and waters strengthens the Nation's security and reduces
reliance on imported energy'' as well as helping reinvigorate American
manufacturing and job growth.
[[Page 62057]]
Accordingly, Executive Order 13795 stated that ``[i]t shall be the
policy of the United States to encourage energy exploration and
production, including on the Outer Continental Shelf (OCS), in order to
maintain the Nation's position as a global energy leader and foster
energy security and resilience for the benefit of the American people .
. . .''
3. Secretarial Orders 3350 and 3360
 Two Secretarial Orders are also relevant to this rulemaking.
Through Secretarial Order 3350, America-First Offshore Energy Strategy,
the Secretary of the Interior (Secretary) took specific steps to
implement Executive Order 13795. Significant to the proposed rule, the
Secretary specifically stated that Secretarial Order 3350 is designed
to implement the President's directives as set forth in Executive Order
13795 to ``ensure that responsible OCS exploration and development is
promoted and not unnecessarily delayed or inhibited.'' The Order
directed Bureau of Ocean Energy Management and the Bureau of Safety and
Environmental Enforcement to take specific actions, but also more
generally expressed a desire for active coordination of energy policy
in order to enhance opportunities for energy exploration, leasing, and
development on the OCS. Secretarial Order 3360 is likewise directed at
continuing to implement Executive Order 13783 and the directive to the
Department to review existing regulations that ``potentially burden the
development or utilization of domestically produced energy resources.''
 These Executive Orders and Secretarial Orders make clear that it is
in the national interest to promote domestic energy development for a
variety of reasons, including stimulating the economy, job creation,
and national security. They also emphasize the importance of reducing
regulatory burdens so that energy producers, and particularly oil,
natural gas, and coal producers, can be encouraged to produce more
energy. Through this rulemaking, ONRR will attempt to further those
policy objectives by two primary means. The first, to provide
mechanisms that simplify reporting. The second, to promote new and
continued domestic energy production. In Section F below, ONRR requests
specific comments on how effectively the proposed rule would implement
the policy objectives stated above, and for additional ways in which
ONRR could further implement those policy objectives.
 ONRR's royalty program is ``a complex and highly technical
regulatory program, in which the identification and classification of
relevant criteria necessarily require significant expertise and entail
the exercise of judgment grounded in policy concerns.'' Amoco Prod. Co.
v. Watson, 410 F.3d 722, 729 (D.C. Cir. 2005) (internal quotations and
citation omitted). FOGRMA grants the Secretary authority to ``prescribe
such rules and regulations as he deems reasonably necessary to carry
out this chapter.'' See 30 U.S.C. 1751(a); see also, e.g., 30 U.S.C.
1719. Re-evaluating the best means of balancing these statutory
priorities within the bounds of the specific commands of the statute,
as called for in the Executive and Secretarial Orders, is well within
the scope of authority that Congress delegated to ONRR under FOGRMA.
C. ONRR's Rulemaking Authority
 Congress gave the Secretary authority to promulgate regulations
concerning ``a comprehensive inspection, collection and fiscal and
production accounting and auditing system to provide the capability to
accurately determine oil and gas royalties, interest, fines, penalties,
fees, deposits, and other payments owed, and to collect and account for
such amounts in a timely manner.'' 30 U.S.C. 1711(a). The Secretary, in
turn, assigned these duties to ONRR's predecessor, a program within the
Minerals Management Service. 47 FR 4751, February 2, 1982; Secretarial
Order 3071, as amended on May 10, 1982; see also 30 CFR 201.100 (2006).
Secretarial Order 3299, as amended on August 29, 2011, created ONRR and
delegated to it the ``royalty and revenue management function of the
Minerals Management Service.''
 ONRR has the authority to amend its rules, consistent in large part
with the policy established in the Executive and Secretarial Orders, so
long as ONRR: (1) Displays ``awareness that it is changing position,''
(2) shows that ``the new policy is permissible under the statute,'' (3)
``believes'' that the new policy is better than the old, and (4)
provides ``good reasons'' for the new policy, which, if the ``new
policy rests upon factual findings that contradict those which underlay
its prior policy,'' must include ``a reasoned explanation . . . for
disregarding facts and circumstances that underlay or were engendered
by the prior policy.'' Fox, 556 U.S. at 515-16.
 Importantly, ONRR is not limited to an analysis of whether facts or
circumstances changed since the 2016 Valuation Rule. Instead, ONRR may
look to other ``good reasons'' to adopt new policy--including the
objectives of certain Executive and Secretarial Orders and weighing
facts differently considering those objectives.
 ONRR does not need to base a revised decision upon a change of
facts or circumstances. A revised rulemaking based ``on a reevaluation
of which policy would be better in light of the facts'' is ``well
within an agency's discretion,'' and ``[a] change in administration
brought about by the people casting their votes is a perfectly
reasonable basis for an executive agency's reappraisal of the costs and
benefits of its programs and regulations.'' Nat'l Ass'n of Home
Builders, 682 F.3d at 1038 and 1043 (citations omitted).
D. What This Proposed Rule Does
1. Index-Based Options for Valuing Federal Gas
 The 2016 Valuation Rule adopted an index-based valuation option for
non-arm's-length sales (that is, sales under contracts that do not
satisfy the ``arm's-length contract'' definition under Sec. 1206.20 or
sales that do not occur under a contract) of unprocessed gas, natural
gas liquids (``NGLs''), and residue gas. The 2016 Valuation Rule set
royalty value at the highest monthly bidweek price (less a specified
deduction) for unprocessed gas and residue gas, and the average monthly
bidweek price (less a specified deduction) for NGLs, from a publicly-
available publication at an accessible index-pricing point. Currently
approved publications can be found at https://www.onrr.gov/Valuation/federal-gas-index-option.htm.
 In the 2016 Valuation Rule, ONRR explained that the gross proceeds
accruing under an arm's-length transaction is generally the most
accurate indicator of value. But given the complexity of non-arm's-
length dispositions, it was appropriate to provide the index-based
valuation option to increase simplicity and reduce administrative
burdens to ONRR and industry.
 Complex valuation situations related to marketable condition,
transportation, and processing are not limited to non-arm's-length
dispositions. So similar benefits--notably reductions to industry's
administrative burdens--could be gained by extending the index-based
valuation option to arm's-length dispositions. Further, because
industry is in the process of altering its accounting and reporting
processes to monitor and use index-based valuation for its non-arm's-
length dispositions, it stands to gain additional efficiencies from
applying those same processes to arm's-length dispositions.
[[Page 62058]]
 ONRR maintains that arm's-length dispositions are most often the
strongest indicator of market value, and that market value is generally
the most appropriate measure for royalty value. This proposed rule
would attempt to further the 2016 Valuation Rule's progress by closing
the gap between royalty values determined using the gross proceeds
accrued under arm's-length dispositions and royalty values determined
under index-based valuation.
 In the 2016 Valuation Rule, ONRR designed the index-based valuation
option to result in royalty values that are generally greater than
those based on gross proceeds. The greater value protected ONRR's
ability to collect at least as much in royalties using index-based
valuation as it would using a non-index method (that is, using gross
proceeds). ONRR stated that any increase in royalty value would be
offset by the reduced administrative burden that the index-based
option's simplicity and clarity afforded a lessee. Based on a review of
data from production months in 2007 through 2010, ONRR determined that
the estimated royalty value using an index-based valuation option would
result in consistently higher royalties due than the average value
received under gross-proceeds-based reporting.
 When ONRR uses the term, ``published average bidweek price,'' or
``bidweek average'' for short, it refers to what many publications call
the ``index'' or ``average'' price. For example, the Platts Inside
FERC's Gas Market Report labels this price as the ``index,'' while the
Natural Gas Intelligence's (NGI) Bidweek Survey labels this price as
the ``average.''
 ONRR proposes to amend 30 CFR part 1206 to specify that, when a
lessee chooses to value unprocessed or residue gas for royalty purposes
using the index-based option, the lessee may use the published bidweek
average price rather than the bidweek high price. Doing so should more
closely match what many lessees would otherwise receive as gross
proceeds and would apply a consistent valuation approach to unprocessed
gas, residue gas, and NGLs.
 ONRR compared the royalties paid based on gross proceeds to the
royalties paid using the 2016 Valuation Rule's index-based valuation
option--as well as to the method proposed in this rule. As outlined in
the Procedural Matters section, overall royalty values under the 2016
Valuation Rule's index-based valuation option are still around $0.04/
MMBtu higher than the prices reported to ONRR for arm's-length sales.
In the proposed rule, the average bidweek price would result in around
$0.09 less per MMBtu. But, in certain areas, there could be greater
increases (offshore Gulf of Mexico) or decreases (most onshore basins)
in royalty value under the index-based valuation option. ONRR is
interested in receiving comments on alternatives that more closely
match the index-based valuation method to the gross proceeds accruing
under arm's-length dispositions across all Federal oil and gas leases.
 Through the proposed rule, ONRR is attempting to address major
concerns with the 2016 Valuation Rule's index-based valuation option
for Federal gas and implement certain Administration policies enacted
following publication of the 2016 Valuation Rule to encourage domestic
oil and gas production and reduce undue regulatory burdens on industry.
The proposed rule would: (1) Extend the index-based valuation option to
all Federal gas dispositions; (2) change the royalty value under the
index-based option for unprocessed and residue gas from the highest
bidweek price to the average bidweek price; (3) update the index-based
transportation deduction to rely on more recent cost data; (4) clarify,
in the unprocessed and processed gas sections, that a lessee may not
report a product's value for royalty purposes as zero or less; and (5)
add language reinforcing ONRR's statutory authority to request and
receive a lessee's and its affiliate's sales and expense records even
in instances where the lessee pays royalties under an index-based
valuation method.
2. Allowance Limits
 For over two decades before the 2016 Valuation Rule, when a lessee
submitted a certain form (form ONRR-4393), and documentation showing
that it had met certain criteria, ONRR would evaluate the submissions
and determine whether to allow that lessee to exceed the regulatory
limits for transportation allowances or processing allowances (request-
to-exceed), or, under a different process, to claim extraordinary
processing costs (request-to-claim). The 2016 Valuation Rule eliminated
those practices by converting the regulatory limits into hard caps,
abolishing the request-to-exceed and request-to-claim processes, and
terminating all approvals ONRR previously granted.
 ONRR has re-evaluated these provisions in light of the
Administration's policy emphasis on domestic energy production and
reduction of regulatory burdens and believes it is appropriate to
reconsider the allowance limits in light of the burdens the 2016
Valuation Rule imposed. The 2016 Valuation Rule's allowance hard caps
increased energy production costs (through increased royalty values) in
situations where a lessee previously had a long-standing ability to
deduct certain costs under the 1988 valuation rule after justifying its
request for an allowance. Providing a lessee with a method to request
and receive approval to exceed the regulatory limits removes a
disincentive for the limited number of lessees that produce from
Federal lands that are less desirable due to the high costs associated
with transportation, processing, or both. In particular, reintroducing
the request-to-exceed and request-to-claim processes could remove a
hard cap's disincentive to produce in remote areas (high movement
costs) or from low quality reservoirs (high treatment costs, processing
costs, or both). It could also provide a lessee an incentive to
continue producing through uncommon or unavoidable circumstances
affecting costs and value.
 ONRR proposes to remove the undue burden on energy production that
the 2016 Valuation Rule's hard caps created when the rule eliminated
the approval burden for ONRR. The proposed rule would revert to the
historical practices with respect to regulatory limits on
transportation costs (50 percent for Federal oil and Federal gas) and
processing costs (66\2/3\ percent for Federal gas), and allow a lessee
to request extraordinary processing-cost allowance approvals. As before
the 2016 Valuation Rule, ONRR would only approve a lessee's request
after reviewing a lessee's documentation for adequacy, reasonableness,
and accuracy.
3. Transportation Allowance for Certain Offshore Gathering Costs
 After the publication of 2016 Valuation Rule, the Administration
adopted policies through certain Executive and Secretarial Orders to
encourage Federal oil and gas production. In response, ONRR is
reexamining its historical practice (1999 through 2016) with respect to
allowing a transportation deduction for certain costs that the
regulations define to be gathering costs. Specifically, ONRR proposes
to reinstate the May 20, 1999, memorandum titled ``Guidance for
Determining Transportation Allowances for Production from Leases in
Water Depths Greater Than 200 Meters.''
 In 1988, the Minerals Management Service (MMS) defined
``gathering'' in regulations for the first time (and it has remained
substantively unchanged since): ```Gathering' means the movement of
lease production to a central accumulation and/or treatment point on
the lease, unit or
[[Page 62059]]
communitized area, or to a central accumulation or treatment point off
the lease, unit or communitized area as approved by BLM or MMS OCS
operations personnel for onshore and OCS leases, respectively.'' See 53
FR 1273, January 15, 1988.
 In effect, those regulations authorized a lessee to deduct certain
costs incurred for transportation off the lease--other than gathering--
as a transportation allowance. In the final rule, MMS rejected an
industry-group's comment to remove the ``excluding gathering'' language
because ``MMS [believed] that gathering is a cost of making oil
marketable, which must be borne exclusively by the lessee.'' 53 FR 1184
at 1190-1191, January 15, 1988.
 MMS also considered numerous comments from industry concerning the
phrase ``or to a central accumulation or treatment point off the lease,
unit or communitized area as approved by BLM or MMS OCS operations
personnel for onshore and OCS leases, respectively.'' The commenters
stated that the phrase was unclear and that it should be removed from
the definition. Several industry commenters recommended that gathering
be limited to the lease or unit area so a transportation allowance
could be obtained for all off lease movement. But MMS kept the proposed
rule's definition intact.
 The operational regulations of both BLM and MMS required that a
lessee place all production in a marketable condition, if economically
feasible, and that a lessee also properly measure all production in a
manner acceptable to those agencies' authorized officials. Unless
specifically approved otherwise, the regulations' requirements were to
be met prior to the production leaving the lease. Thus, MMS did not
believe that any allowances should be granted for costs incurred by a
lessee when approval was granted for the removal of production from the
lease, unit, or communitized area when the purpose was to treat
production or accumulate production for delivery to a purchaser prior
to meeting the requirements of any operational regulations. 53 FR 1184
at 1193, January 15, 1988.
 MMS published the 1988 rule prohibiting the deduction of all
gathering costs with knowledge of the costs of deepwater gathering.
While the 1987 draft final rule that preceded the 1988 rule
contemplated allowing deductions for deepwater gathering costs, the
1988 rule rejected any deduction for deepwater gathering costs. The
1987 draft final rule provided that if a lessee incurs extraordinary
costs for gathering from frontier or deepwater areas, and those costs
related to unusual or unconventional operations, it may apply to MMS
for an allowance. Such an allowance would only be granted if the costs
were associated with offshore leases located in water depths in excess
of 400 meters. 52 FR 30826 at 30858, August 17, 1987.
 But in the preamble to the 1988 rule MMS concluded that it would
not allow a deduction of any gathering costs, including deepwater
gathering. MMS concluded that the burdens placed on the lessee by the
environment in which it operates were matters considered at the time
the lease was issued, and reflected in the amount of bonus bids and, in
some cases, the royalty rate. MMS determined that if a lessee was
entitled to further economic relief, it would be inappropriate to
provide that relief through an adjustment to the value of the
production using methods that were inconsistent with historical
practice and interpretation of a lessee's express obligation to place
production in marketable condition at no cost to the Federal lessor. 53
FR 1184 at 1205 (January 15, 1988).
 In sum, ONRR and its predecessor, MMS, by regulation prohibited the
deduction of all gathering, even for deepwater, with gathering defined
to include all movement upstream of any ``central accumulation point
and/or treatment point.'' Preamble language clarified upstream of a
``central accumulation point and/or treatment point'' to mean upstream
of the point at which oil and gas is in marketable condition and
metered for royalty purposes.
 In 1998, MMS published two Federal Register Notices (63 FR at 38355
and 63 FR 56217) requesting input on whether MMS should change the
``gathering'' definition to allow a lessee to deduct costs associated
with moving bulk production from subsea wellheads to offshore floating
platforms. MMS requested further comments on what criteria to use when
differentiating between the movement that is gathering and the movement
that is transportation.
 MMS chose not to amend its regulations after receiving comments on
those Federal Register notices. Instead, the Associate Director for
MMS's Royalty Management Program implemented policy on deepwater
gathering through a May 20, 1999, memorandum titled ``Guidance for
Determining Transportation Allowances for Production from Leases in
Water Depths Greater Than 200 Meters'' (Deepwater Policy).
 The Deepwater Policy provided that production from a lease, any
part of which lies in water deeper than 200 meters, may qualify for a
transportation allowance. The following guidelines also applied:
 The transportation allowance was to be determined in
accordance with then-current regulations.
 The costs of movement was allocated between the royalty
bearing and non-royalty bearing substances.
 Movement prior to a central accumulation point was
considered gathering. A central accumulation point may be a single
well, a subsea manifold, the last well in a group of wells connected in
series, or a platform extending above the surface of the water.
Movement beyond the point was considered transportation.
 Leases and units were treated similarly.
 To qualify for a transportation allowance, the movement
had to be to a facility not located on a lease adjacent to the lease on
which the production originated. An adjacent lease was defined as any
lease with at least one point of contact with the producing lease/unit.
Typically, for a single lease, there would be eight leases adjacent to
a qualifying deep-water lease.
 Allowances for subsea completions not located in water
deeper than 200 meters could be considered on a case-by-case basis.
 In the proposed 2016 Valuation Rule (80 FR 608), ONRR proposed to
rescind the Deepwater Policy because, ``Under Kerr-McGee Corp., 147
IBLA 277, 282 (Jan. 29, 1999) almost all of the movement the
[Deepwater] Policy allows as a transportation allowance is, in
actuality, non-deductible `gathering' under ONRR's current valuation
regulations. We determined that the Deep-Water Policy is inconsistent
with our regulatory definition of ``gathering'' and Departmental
decisions interpreting that term.'' Id. at 624.
 In the 2016 Valuation Rule's preamble, ONRR included language that
rescinded the Deepwater Policy, explaining that MMS intended for the
Deepwater Policy to incentivize deepwater leasing by allowing lessees
to deduct broader transportation costs than the regulations allowed.
ONRR then concluded that the Deepwater Policy had served its purpose
and was no longer necessary.
 In the 2017 Repeal Rule, ONRR stated that by reinstating the prior
regulations, ONRR's longstanding Deepwater Policy would remain in
effect, and that ONRR would continue to implement the Deepwater Policy
to the extent that it is consistent with the prior regulations. ONRR
also asserted that the Deepwater Policy is a matter that is appropriate
to revisit and reconsider. Industry
[[Page 62060]]
endorsed ONRR's attempt to revive the policy and public interest groups
opposed the effort arguing the Deepwater Policy allowed, in the form of
a transportation allowance, an ``improper deduction under ONRR's
regulatory scheme.''
 As discussed above, ONRR is in the process of reevaluating its
rules in light of Executive Orders 13783 and 13795, which call on
Federal agencies to promote and unburden domestic energy production,
and the Secretarial Orders encouraging robust and responsible
exploration and development of Outer Continental Shelf (OCS) resources.
 A subsea completion exists where the wellhead is located on the
seafloor, and bulk production is moved to the production platform
through a series of manifolds and flow lines. This is different--and
significantly more complex--than a topside completion, where the
wellhead is located on a platform above the water surface. A deepwater
lessee must typically move offshore production great distances relative
to other areas before it reaches the wellhead--where separation,
treatment, and measurement for royalty purposes may occur. Due to the
unique environmental and operational factors in deepwater, a lessee may
be unable (without great costs, impaired engineering efficiency, or
both) to satisfy ONRR's ``gathering'' definition before production
reaches the platform.
 The proposed rule would effectively revert to ONRR's historical
policy (1999 to 2016) that was embodied in the Deepwater Policy and
permitted a lessee producing from the OCS to take a transportation
allowance for certain costs that the pre-2016 rules defined as
gathering costs.
 ONRR proposes to remove the language in the ``gathering''
definition under Sec. 1206.20 defining ``gathering'' to include ``any
movement of bulk production from the wellhead to a platform offshore.''
ONRR also proposes to remove the language that the 2016 Valuation Rule
added in the transportation allowance sections under Sec. Sec.
1206.110(a)(2)(ii) and 1206.152(a)(2)(ii) that provides ``[f]or
[production from] the OCS, the movement of [production] from the
wellhead to the first platform is not transportation.'' ONRR proposes
to replace the removed language from language consistent with the
Deepwater Policy for production from water deeper than 200 meters and
water shallower than 200 meters. For example, the Federal oil
regulations under Sec. 1206.110 would state that: ``For oil produced
on the OCS in waters deeper than 200 meters, the movement of oil from
the wellhead to the first platform is transportation for which a
transportation allowance may be claimed'' and ``On a case-by-case
basis, you may apply to ONRR to have your actual, reasonable and
necessary costs of the movement of oil produced on the OCS in waters
shallower than 200 meters from the wellhead to the first platform to be
treated as transportation for which a transportation allowance may be
claimed.''
4. Misconduct, the Default Provision, and Contract Signature
Requirement
 ONRR proposes to amend certain sections under 30 CFR part 1206 to
effectively return the requirements for the following topics, for
Federal oil and gas and Federal and Indian Coal, to the practices in
place prior to the 2016 Valuation Rule. The proposed rule would delete:
(1) The definition of ``misconduct'' from Sec. 1206.20; (2) the
default provision from Sec. Sec. 1206.105, 1206.144, 1206.254, and
1206.454, as well as references in other sections; and (3) the
requirement that all contracts be signed by all parties to the contract
from 30 CFR 1207.5, 1206.104(g)(1), 1206.143(g)(3), 1206.253(g)(1), and
1206.453(g)(1).
 In the 2015 Proposed Valuation Rule and 2016 Valuation Rule, ONRR
distinguished between the ``misconduct'' definition in the civil
penalty regulations and the ``misconduct'' definition in the valuation
regulations at Sec. 1206.20. Industry stakeholders have argued that
the ``misconduct'' definition in the valuation regulations is too broad
and could be misapplied.
 Under Sec. 1210.30, ONRR requires lessees to ``submit accurate,
complete, and timely information,'' which means that lessees are
required to correct simple reporting errors when the lessee or ONRR
discovers them--regardless of whether the errors constitute misconduct.
ONRR therefore agrees that the new definition of misconduct is unduly
burdensome and duplicative. As noted below, ONRR is requesting comments
on further revisions to its rules to replace the usage of the term
``misconduct'' since the definition of misconduct may be eliminated in
Sec. 1206.20.
 Like the ``misconduct'' definition, industry believes that ONRR
could misapply the default provision in ways that undermine the other
pillars of our regulatory scheme (which include, for example, basing
allowances on reasonable actual costs, identifying where royalties are
calculated, and looking to arm's-length transactions as the best
indicator of value). While the purpose of the default provision was to
provide a means for establishing royalty value when the most frequently
used valuation methods are unavailable or unworkable, ONRR believes
that the default provision is unnecessary considering successful
historical practice without it. For years, ONRR successfully performed
compliance activities and, where appropriate, exercised Secretarial
discretion to establish royalty values absent a default provision.
Given the recent direction in Executive Orders 13783 and 13795 to
promote domestic energy production, ONRR believes that it unintendedly
increased uncertainty due to the perception that ONRR might apply the
default provision in place of accurate lessee reporting, thereby
creating a regulatory burden for industry.
 In the 2016 Valuation Rule, ONRR stated that to fully verify the
correctness of royalty reports and payments, ONRR needs to see that all
parties signed the contract. Then, in the 2017 Repeal Rule, ONRR
provided 5 reasons why a contract that was not signed by all parties
could be sufficient to determine compliance:
 1. ``[U]nsigned, written agreements may be binding, legally
enforceable contracts.''
 2. The ``provision contradicted the definition of `contract' in the
rule itself, which defined `contract' as any oral or writing agreement
. . . that is enforceable by law.''
 3. The preamble ``stated that ONRR could discount or ignore an
arm's-length contract 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.''
 4. ``[T]he 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.''
 5. ``[T]he 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.''
 ONRR did not address how we might fulfill that statutory mandate
without the signature requirement in the 2017 Repeal Rule because ONRR
has fulfilled that mandate for decades without an additional
requirement. If finalized as proposed, ONRR would evaluate a party's
course of performance under all
[[Page 62061]]
contracts--signed and unsigned--consistent with its historical
practice.
 ONRR proposes to eliminate the requirement that a lessee create,
maintain, and provide contracts signed by all parties, but would keep
the requirement that has existed since 1988 that contracts be in
written form. The requirement that lessees place contracts in writing
is found under 30 CFR 1207.5, 1206.104(g)(1), 1206.143(g)(3),
1206.253(g)(1), and 1206.453(g)(1).
 Here, ONRR, in an effort to relieve certain regulatory burdens the
2016 Valuation Rule places on industry, is reevaluating the requirement
for a lessee to maintain signed contracts. Without a requirement to
maintain signed contracts, ONRR possesses broad authority to
investigate and question the validity of any contract. For example,
ONRR may choose to exercise that authority in situations where ONRR
suspects that an arm's-length or non-arm's-length contract: (1) Fails
to reflect actual performance, (2) shows a breach of the lessee's duty
to market for the benefit of the lessor, or (3) shows lessee
misconduct. Thus, ONRR estimates little, if any, impact on our methods
for determining compliance. Moreover, ONRR recognizes that contracts
may be valid and enforceable, as a matter of law, despite the absence
of one or more signatures.
5. Citation to Legal Precedent With Valuation Determination Requests
 ONRR proposes to eliminate the requirements under 30 CFR
1206.108(a)(5), 1206.148(a)(5), 1206.258(a)(5) and 1206.458(a)(5) for a
lessee to include citations to legal precedents when requesting a
valuation determination.
 ONRR encourages a lessee to provide, along with the lessee's
valuation request, any citations to precedent that it believes are
persuasive. At the same time, ONRR is familiar with, and commonly a
party to, matters that generate precedent for Federal oil and gas,
Federal coal, and Indian coal royalty valuation. So, although citations
might expedite the processing time for an industry request, it is not
necessary to require industry to provide citations to precedent.
Further, ONRR believes that it would be unproductive to attempt to
enforce or litigate such a requirement, especially because a failure to
include a citation to precedent may not, on its own, provide a
sufficient reason to deny an otherwise valid request for a valuation
determination. Finally, ONRR is reevaluating whether it inadvertently
created an undue burden on industry by requiring lessees to provide
legal precedents with valuation determination requests because that
requirement might require a lessee to retain legal counsel instead of
allowing a lessee's non-legal staff to more expeditiously communicate
with ONRR regarding a valuation determination request.
6. Coal Valued as Electricity
 ONRR proposes to amend 30 CFR part 1206 to remove the requirements
under Sec. Sec. 1206.252 (Federal coal) and 1206.452 (Indian coal) to
value coal based on the first arm's-length sale as electricity.
Instead, ONRR proposes to require a lessee to value that coal based on
certain other arm's-length sales, or, where those sales do not exist,
to request a valuation determination under 30 CFR 1206.258 (Federal
coal) or 1206.458 (Indian coal). ONRR defended the coal valuation rules
but, upon consideration of the parties' briefs and, after receiving the
Court's ruling, it has determined that ONRR should revisit the coal
rules to provide an alternative requirement that maintains the royalty
value of coal using a less burdensome and controversial method. This
would bring the ONRR's regulations in conformity with the Court's
ruling in Cloud Peak, supra, and remove the burden and cost to ONRR and
industry to obtain and validate the information.
7. The ``Coal Cooperative'' Definition
 ONRR proposes to amend 30 CFR part 1206 to remove the ``coal
cooperative'' definition under Sec. 1206.20 and all other references
thereto. ONRR is attempting to relieve concerns with the definition's
applicability and meaning. While the Court, in Cloud Peak, did not find
the coal cooperative definition to be arbitrary and capricious, the
Court offered strong criticism of the definition. Accordingly, this
amendment would harmonize the ONRR's rules with the Court's statements
in Cloud Peak, supra.
8. Civil Penalties for Payment Violations
 ONRR proposes to amend Sec. 1241.70 to clarify that--for payment
violations only--ONRR would consider the monetary impact of the
entity's conduct when assessing a civil penalty. Section 1241.70(b)
arguably created an ambiguity as to whether ONRR considers the unpaid,
underpaid, or late-paid amounts when assessing a penalty for a payment
violation under Sec. 1241.50. Clarifying this ONRR civil penalty
practice would support Executive Order 13892--Promoting the Rule of Law
Through Transparency and Fairness in Civil Administrative Enforcement
and Adjudication.
9. Aggravating and Mitigating Circumstances
 ONRR proposes to amend Sec. 1241.70 to clarify that ONRR may
consider aggravating and mitigating circumstances to determine an
appropriate penalty. ONRR considers aggravating and mitigating
circumstances on a case-by-case basis to increase or decrease the
penalty amount in a Failure to Correct Civil Penalty Notice (FCCP) or
Immediate Liability Civil Penalty Notice (ILCP). Potential aggravating
circumstances may include, but are not limited to, when the violation
may also be a criminal act, when the violation occurs because a
violator calculated the cost of compliance is more than the cost of a
penalty, or when a violator has no history of noncompliance for the
violation at hand but has an extensive history of noncompliance for
other violation types. Mitigating circumstances are generally
conditions where a lessee has limited control including, but not
limited to, operational impacts resulting from the unexpected illness
or death of an employee, natural disasters, pandemics, acts of
terrorism, civil unrest, or armed conflict or delays caused by
government action or inaction, including as a result of a government
shutdown or ONRR-system downtime. Consistent with the general approach
of Executive Order 13924 ``Regulatory Relief to Support Economic
Recovery'' and Executive Order 13892 ``Promoting the Rule of Law
Through Transparency and Fairness in Civil Administrative Enforcement
and Adjudication,'' the failure of a lessee to conform to formal or
informal agency guidance does not, in itself, establish a violation,
while good faith efforts to comply with formal or informal agency
guidance constitute mitigating circumstances and may serve as a
rationale to decline issuing enforcement penalties entirely.
10. Administrative Law Judges May Not Withdraw Stay of Civil Penalty
Accruals
 ONRR proposes to amend Sec. 1241.11 to return to its historical
practice of guaranteeing an appellant the benefit of a stay of the
accrual of a civil penalty during an appeal if granted by the
Department's administrative law judge (``ALJ''). Specifically, the
proposed rule would remove Sec. 1241.11(b)(5), which states:
``Notwithstanding paragraphs (b)(1), (2), (3), and (4) of this section,
if the ALJ determines that your defense to a Notice is frivolous, and a
civil penalty is owed, you will forfeit the benefit of the stay, and
penalties will be
[[Page 62062]]
calculated as if no stay had been granted.''
 When ONRR adopted the 2016 Civil Penalty Rule, Sec. 1241.11(b)(5)
was added. When API challenged the 2016 Civil Penalty Rule, the
challenge was rejected except as to Sec. 1241.11(b)(5). API, 366 F.
Supp. 3d at 1310. Because Sec. 1241.11(b)(5) was invalidated through a
judicial proceeding and ONRR is not pursuing a review of this portion
of the Court's ruling in API's ongoing appeal, ONRR proposes to remove
the paragraph from the 2016 Civil Penalty Rule.
E. Economic Analysis
 ONRR summarized the estimated changes to royalties and regulatory
costs the proposed rule may have on potentially affected groups,
including industry, the Federal Government, and State and local
governments. A number of the proposed Federal oil and gas amendments
would result in decreased royalty collections.
 ONRR notes that changes to royalties are transfers that are
distinguishable from regulatory costs (or cost savings). The estimated
changes in royalties assessed will change both the private cost to the
lessee and the amount of revenue collected by the Federal government
and disbursed to State and local governments. The net impact of the
proposed amendments is an estimated $42.1 million annual decrease in
royalty collections. This represents a decrease of less than one-half
of one percent of the total Federal oil and gas royalties ONRR
collected in 2018. However, the financial impact, as evident in the
total annual estimate reflected above, does impact the royalty
disbursements for the Treasury and States who are stakeholders and
recipients of ONRR's distributions.
 Increased domestic energy production protects the United States
from supply disruptions abroad and may also lead to an overall increase
in royalty collections. Further, an industry more focused on domestic
capital expenditures may create jobs and increase cash circulation in
the United States' economy. As such, ONRR recognizes that the United
States benefits from domestic energy production beyond the production's
royalty value. In the instances where this rule proposes to alter
royalties, ONRR is particularly interested in public comments on
whether, and to what extent, the proposed amendments would impact
domestic energy exploration and energy production, create economic
opportunity, or otherwise provide justification to alter--or not--those
transfer payments between the United States and its lessees.
 ONRR also estimates that the Federal oil and gas industry would
experience increased annual administrative costs of $2.58 million if
ONRR adopts the entirety of this rule as proposed. As discussed below,
this is the net impact of various cost increasing and cost saving
proposals.
 ONRR estimates that the proposed rule would have no economic impact
on Federal and Indian coal. Please note that, unless otherwise
indicated, numbers in the tables in this section are rounded to the
nearest thousand, and that the totals may not match due to rounding.
1. Federal Oil and Gas
i. Industry
 This table shows the change in royalties by rule provision for the
first year and each year thereafter:
 Summary of Proposed Changes to Oil & Gas Royalties Paid (Annual)
------------------------------------------------------------------------
 Net change in
 Rule provision royalties paid
 by lessees
------------------------------------------------------------------------
Index-Based Valuation Option Extended to Gas $5,620,000
 Dispositions...........................................
Index-Based Valuation Option Extended to NGL 21,141,000
 Dispositions...........................................
High to Midpoint Index Price for Non-Arm's-Length Gas (4,488,000)
 Dispositions...........................................
Transportation Deduction Non-Arm's-Length Index-Based (7,121,000)
 Valuation Option.......................................
Gas Transportation Allowances........................... (279,000)
Oil Transportation Allowances........................... (11,000)
Gas Processing Allowances............................... (9,942,000)
Extraordinary Processing Allowances..................... (11,131,000)
Deepwater Policy........................................ (35,900,000)
 ---------------
 Total............................................... (42,111,000)
------------------------------------------------------------------------
 ONRR estimates the administrative cost savings from optional use of
the index-based valuation method for gas and NGL sales, and
administrative costs from the transportation allowance for certain
gathering activities covered by the Deepwater Policy. These
administrative costs to industry total approximately $2.58 million
annually.
 Summary of Annual Administrative Impacts to Industry
------------------------------------------------------------------------
 Cost (cost
 Rule provision savings)
------------------------------------------------------------------------
Administrative Benefit for Index-Based Valuation Option ($1,356,000)
 for Gas & NGLs.........................................
Administrative Cost for Deepwater Policy................ 3,936,000
 ---------------
 Total............................................... 2,580,000
------------------------------------------------------------------------
 ONRR also estimates industry will incur a one-time administrative
cost savings of $4.5 million from the simplification of reporting
process and transportation allowances associated with the optional use
of the index-based valuation method. These costs are only calculated
one time and then used to break out allowed from disallowed costs in
reported transportation and processing allowances.
[[Page 62063]]
 One-Time Administrative Impacts to Industry
------------------------------------------------------------------------
 Rule provision Cost savings
------------------------------------------------------------------------
Administrative Cost-savings in lieu of Unbundling $4,520,000
 related to Index-Based Valuation Option for Gas & NGLs.
------------------------------------------------------------------------
 To perform this economic analysis, ONRR reviewed royalty data for
Federal oil, condensate, residue gas, unprocessed gas, fuel gas, gas
lost--flared or vented, carbon dioxide, sulfur, coalbed methane, and
natural gas products (product codes 03, 04, 15, 16, 17, 19, 39, 07, 01,
02, 61, 62, 63, 64, and 65) from the last five calendar years, 2014-
2018. ONRR believes that the vast majority of that reporting was made
in compliance with the rules in place prior to the 2016 Valuation Rule.
ONRR used five calendar years of royalty data because this longer time
period helps smooth data to reduce volatility caused by fluctuations in
commodity pricing and volume swings. ONRR used these data without
adjusting for previous rulemakings because at the time of this
analysis, a significant number of lessees and operators had not yet
complied with the 2016 Valuation Rule's provisions due to its
implementation delays, including the 2017 Repeal Rule, the subsequent
2019 Vacatur, and ONRR's two dear reporter letters providing industry
with additional time to come into compliance with the 2016 Valuation
following its reinstatement. ONRR adjusted the historical data in this
analysis to 2018 dollars using the Consumer Price Index (all items in
U.S. city average, all urban consumers) published by the Bureau of
Labor Statistics (BLS). Based on ONRR's auditing experience, some
companies aggregate their volumes (reported in thousand cubic feet
(Mcf) and in a metric of energy content--one million British thermal
units (MMBtu) for natural gas) in pools, and then sell the natural gas
under multiple contracts. Lessees report those sales and dispositions
using the ``POOL'' sales type code. Only a small portion of gas sales
were non-arm's-length. Thus, ONRR used estimates of 10 percent of the
POOL volumes in the economic analysis of non-arm's-length dispositions
and 90 percent of the POOL volumes in the economic analysis of arm's-
length dispositions. ONRR requests comments specific to how it could
more accurately estimate the allocation between arm's-length and non-
arm's-length sales.
Change in Royalty 1: Using Index-Based Valuation Option to Value
Federal Unprocessed Gas, Residue Gas, Fuel Gas, and Coalbed Methane
 To estimate the royalty impact of the option to pay royalties using
index-based valuation, ONRR reviewed the reported royalty data for all
gas sales except for non-arm's-length (discussed below), future
valuation agreements, and percentage of proceeds sales. ONRR also
adjusted the POOL sales down to 90 percent (as described above), which
were spread across 10 major geographic areas with active index prices.
The 10 areas account for over 95 percent of all Federal gas produced.
ONRR assumes the remaining five percent of Federal gas lessees will not
likely elect the index-based method as areas outside of major producing
basins may have infrastructure limitations or limited access to index
pricing. The 10 geographic areas are:
Offshore Gulf of Mexico
Big Horn Basin
Green River Basin
Permian Basin
Piceance Basin
Powder River Basin
San Juan Basin
Uinta Basin
Williston Basin
Wind River Basin
 To calculate the estimated impact, ONRR:
 (1) Identified the monthly bidweek price index, published by Platts
Inside FERC, applicable to each area--Northwest Pipeline Rockies for
Green River, Piceance and Uinta basins; El Paso San Juan for San Juan
basin; Colorado Interstate Gas for Big Horn, Powder River, Williston,
and Wind River basins; El Paso Permian for Permian basin; and Henry Hub
for the Gulf of Mexico. ONRR determined price index applicability based
on proximity to the producing area and the frequency by which ONRR's
audit and compliance staff verify these index prices in sales
contracts. ONRR is aware that not all sales in an area are based off
these indices and requests further comment to improve this analysis.
 (2) Subtracted the transportation deduction as modified by the
proposed rule (detailed in the transportation section below) from the
midpoint index price identified in step (1).
 (3) Multiplied the royalty volume by the index price identified per
region, less the transportation deduction calculated in step (2).
 (4) Totaled the reported royalties less allowances reported on the
monthly royalty report (form ONRR-2014) and the estimated royalties
based on the index-based valuation option calculated in step (3).
 (5) Calculated the annual average of reported royalties and
estimated index-based royalties calculated in step (4) by dividing by
five (number of years in the analysis).
 (6) Subtracted the difference between the totals calculated in step
(5).
 ONRR anticipates that some lessees will choose to report to ONRR
using this simpler method, saving administrative costs (described in
detail below in Cost Savings 1 and Cost Savings 2, while other lessees
will continue to calculate and deduct the actual costs they incur. ONRR
cannot accurately estimate how many lessees will elect to use the index
valuation method since many factors that are currently unquantifiable
will drive a lessee's decision. For the purposes of this analysis, ONRR
assumed that half of lessees would choose the alternative index-based
valuation method to value dispositions eligible for the election. ONRR
invites public comment on this assumption, and on other methods ONRR
could use to more accurately estimate the economic impact of this
election. ONRR's assumption of a 50 percent reduction is an attempt to
simplify the myriad factors such as, simpler accounting methods for
industry, company-specific break-even analysis, and simplified
allowance unbundling administrative calculations. ONRR also broke out
the Gulf of Mexico from the other onshore basins listed above because
it accounts for approximately 30 percent of the total Federal gas sales
used in this analysis, as well as having different complexities related
to offshore gas production, when compared to onshore areas.
 ONRR estimates that this change will increase annual royalty
payments by approximately $5.3 million. This estimate represents an
average increase of approximately one percent, or $0.04 per MMBtu,
based on an annualized royalty volume of 296,440,024 MMBtu. ONRR chose
not to include POP sales in the above methodology because the sales are
reported inclusive of the NGL value and net of transportation and
[[Page 62064]]
processing costs. To try to account for the change in value associated
with POP contracts, ONRR applied the $0.04 per MMBtu calculated above
to the annualized royalty volume for APOP sales of 158,772,452 MMBtu.
The total estimated annual average impact is a $5.6 million increase in
royalties. ONRR recognizes that it is not accounting for the value of
APOP NGLs, however ONRR does not have a reasonable method to break out
those components from the available data and would welcome comment on
this matter.
 Annual Net Change in Royalties Paid Using Index Option for Gas Dispositions
----------------------------------------------------------------------------------------------------------------
 Gulf of Mexico Onshore basins Total
----------------------------------------------------------------------------------------------------------------
Annualized Reported Royalties.................................. $235,065,000 $541,124,000 $776,189,000
Royalties Estimated using Index-Based Valuation Option......... 250,183,000 536,564,000 786,747,000
Difference..................................................... 15,118,000 (4,560,000) 10,558,000
Change per MMBtu............................................... 0.18 (0.02) 0.04
% Change....................................................... 6 (1) 1
Annualized POP Royalties using Index-Based Valuation Option.... .............. ............... (681,768)
 ------------------------------------------------
 50% of lessees choose this option.......................... .............. ............... 5,620,000
----------------------------------------------------------------------------------------------------------------
Change in Royalties 2: Using the Index-Based Valuation Option To Value
Sales of Federal NGLs
 Similar to the changes to Federal unprocessed gas, residue gas,
pipeline fuel, and coalbed methane, a lessee will have the option to
pay royalties on Federal NGLs using an index-based value less a
theoretical processing allowance and be allowed an adjustment for
transportation costs and fractionation costs, which account for the
prices realized at the various NGL hubs. ONRR used the same 2014-2018
calendar years for all NGL sales except for non-arm's-length and future
valuation agreements. ONRR also adjusted the POOL sales to 10 percent
(as described above). These sales were spread across the same 10 major
geographic areas with active index prices for this analysis. To
calculate the estimated impact, ONRR:
 (1) Identified the Platts Oilgram Price Report Price Average
Supplement (Platts Conway) or OPIS LP Gas Spot Prices Monthly (OPIS
Mont Belvieu) for published monthly midpoint NGL prices per component
applicable to each area-- Platts Conway for Williston and Wind River
basins; and OPIS Mont Belvieu non-TET for the Gulf of Mexico, Big Horn,
Green River, Permian, Piceance, Powder River, San Juan, and Uinta
basins. In ONRR's audit experience, OPIS' prices are used to value NGLs
in contracts more frequently at Mont Belvieu, and Platts' prices are
used more frequently at Conway.
 (2) Calculated an NGL basket price (a weighted average price to
group the individual NGL components to a weighted price), which were
compared to the imputed price from the monthly royalty report. The
baskets illustrate the difference in the gas composition between
Conway, Kansas and Mont Belvieu, Texas. The NGL basket hydrocarbon
allocations are:
------------------------------------------------------------------------
 Platts Conway Basket OPIS Mont Belvieu Basket
------------------------------------------------------------------------
Ethane-propane (EP mix) 40%............ Ethane 42%
Propane 28%............................ Non-TET Propane 28%
Isobutane 10%.......................... Non-TET Isobutane 6%
Normal Butane 7%....................... Normal Butane 11%
Natural Gasoline 15%................... Natural Gasoline 13%
------------------------------------------------------------------------
 (3) Subtracted the current theoretical allowance for processing
deductions, as well as fractionation costs and transportation costs
referenced in the current regulations and published online at https://www.onrr.gov, as shown in the table below from the NGL basket price
calculated in step (2):
 NGL Deduction
 [$/gal]
----------------------------------------------------------------------------------------------------------------
 Gulf of Mexico New Mexico Other areas
----------------------------------------------------------------------------------------------------------------
Processing...................................................... $0.10 $0.15 $0.15
Transportation and Fractionation................................ 0.05 0.07 0.12
 Total (/gal)................................................ 0.15 0.22 0.27
----------------------------------------------------------------------------------------------------------------
 (4) Multiplied the royalty volume by the index price identified for
each region, less the NGL deduction calculated in step (3).
 (5) Totaled the royalty value less allowances reported on the
monthly royalty report, and the estimated royalties based off the
index-based valuation option calculated in step (4).
 (6) Calculated the annual average of reported royalties and
estimated index-based royalties calculated in step (5) by dividing by
five (number of years in this analysis).
 (7) Subtracted the difference between the totals calculated in step
(6).
 Because ONRR assumed that 50 percent of lessees would choose this
option for eligible dispositions, ONRR reduced the total estimate by 50
percent in the following table, and ONRR invites public comments on
this assumption and any other method available to more accurately
quantify the economic impact of this election. ONRR estimates that this
change will increase annual royalty payments by approximately
[[Page 62065]]
$21.1 million. This estimate represents an average increase of
approximately 17 percent or $0.0894 per gallon, based on an annualized
royalty volume of 475,257,250 gallons.
 Annual Net Change in Royalties Paid Using Index Option for NGL Sales
----------------------------------------------------------------------------------------------------------------
 Gulf of Mexico New Mexico Other areas Total
----------------------------------------------------------------------------------------------------------------
Annualized Reported Royalties................... $74,438,000 $67,637,000 $70,072,000 $212,147,000
Royalties Estimated using Index-Based Valuation 77,068,000 66,397,000 110,962,000 254,428,000
 Option.........................................
Difference...................................... 2,630,000 (1,240,000) 40,891,000 42,281,000
Change per gallon............................... 0.0174 (0.0081) 0.2439 0.0894
% Change........................................ 3 (2) 37 17
 ---------------------------------------------------------------
 50% of lessees choose this option........... .............. .............. .............. 21,141,000
----------------------------------------------------------------------------------------------------------------
Change in Royalties 3: Using the Average Index Price Versus the Highest
Published Index Price to Value Non-Arm's-Length Federal Unprocessed
Gas, Residue Gas, Coalbed Methane, and NGLs
 As noted above, index-based valuation will change from using the
highest published price for a specific index-pricing point to using the
average published bidweek price for the index-pricing point. To
estimate the royalty impact of this change to the index-based valuation
option, ONRR used reported royalty data using non-arm's-length
(``NARM'') sales and 10 percent of the POOL sales type codes based on
the assumption above in the same 10 major geographic areas with active
index-pricing points, also listed above.
 To calculate the estimated impact, ONRR:
 (1) Identified the Platts Inside FERC published monthly midpoint
and high prices for the index applicable to each area--Northwest
Pipeline Rockies for Green River, Piceance and Uinta basins; El Paso
San Juan for San Juan basin; Colorado Interstate Gas for Big Horn,
Powder River, Williston, and Wind River basins; El Paso Permian for
Permian basin; and Henry Hub for the Gulf of Mexico.
 (2) Multiplied the royalty volume by the published index prices
identified for each region.
 (3) Totaled the estimated royalties using the published index
prices calculated in step (2).
 (4) Calculated the annual average index-based royalties for both
the high and volume-weighted-average prices calculated in step (3) by
dividing by five (number of years in this analysis).
 (5) Subtracted the difference between the totals calculated in step
(4).
 Because ONRR assumes that 50 percent of lessees would choose this
option, ONRR reduced the total estimate by 50 percent in the following
table, but ONRR invites public comment on this assumption and any other
method available to more accurately quantify the economic impact. ONRR
estimates that the result of this change is a decrease in annual
royalty payments of approximately $4.5 million. This estimate
represents an average decrease of approximately three percent or nine
cents ($0.09) per MMBtu, based on an annualized royalty volume of
93,301,478 MMBtu (for NARM and 10 percent POOL reported sales type
codes).
 Annual Change in Royalties Paid Due to High to Midpoint Modification for Non-Arm's-Length Sales of Natural Gas
----------------------------------------------------------------------------------------------------------------
 Gulf of Mexico Onshore basins Total
----------------------------------------------------------------------------------------------------------------
Royalties Estimated Using High Index Price..................... $107,736,000 $198,170,000 $305,907,000
Royalties Estimated Using Published Average Bidweek Price...... 107,448,000 189,483,000 296,931,000
Difference..................................................... (288,000) (8,687,000) (8,975,000)
Change per MMBtu............................................... (0.01) (0.14) (0.10)
% Change....................................................... 0 (5) (3)
 ------------------------------------------------
 50% of lessees choose this option.......................... .............. ............... (4,488,000)
----------------------------------------------------------------------------------------------------------------
NARM and 10% of POOL Sales Type Codes.
Change in Royalties 4: Modifying the Index-Based Valuation Option
Transportation Deduction Used to Value Non-Arm's-Length Federal
Unprocessed Gas, Residue Gas, Coalbed Methane, and NGLs
 ONRR chose to update the transportation deductions applicable to
non-arm's-length index-based valuation to reflect changes in industry
transportation contracts terms and more recent allowance data reported
to ONRR. To estimate the royalty impact of the modification to the
transportation deduction, ONRR used reported royalty data using NARM
and 10 percent of the POOL sales type codes from the same 10 major
geographic areas with active index-pricing points listed above.
 To calculate the estimated impact, ONRR:
 (1) Identified appropriate areas using Platts Inside FERC index
prices (see list above).
 (2) Calculated the transportation deduction as published in the
current regulations and the deduction outlined in the table below for
each area identified in step (1).
[[Page 62066]]
 Transportation Deduction of Index-Based Valuation Option for Gas ($/
 MMBtu)
------------------------------------------------------------------------
 Current 2019 proposed
 Element regulations rule
------------------------------------------------------------------------
Gulf of Mexico %........................ 5 10
Gulf of Mexico Low Limit................ $0.10 $0.10
Gulf of Mexico High Limit............... 0.30 0.40
Other Areas %........................... 10 15
Other Areas Low Limit................... 0.10 0.10
Other Areas High Limit.................. 0.30 0.50
------------------------------------------------------------------------
 (3) Multiplied the royalty volume by the applicable transportation
deduction identified for each area calculated in step (2).
 (4) Totaled the estimated royalty impact based off both
transportation deductions calculated in step (3).
 (5) Calculated the annual average royalty impact for both methods
calculated in step (4) by dividing by five (number of years in this
analysis).
 (6) Subtracted the difference between the totals calculated in step
(5).
 Because ONRR estimates that 50 percent of lessees will choose this
option, ONRR reduced the total estimate by 50 percent. Please note that
the figures in the table below represent the difference between the
current transportation adjustment percentage and the percentage under
the index-based valuation option. ONRR estimates the change will result
in a decrease in annual royalty payments of approximately $7.1 million.
This estimate represents an average decrease of approximately 65
percent or 15 cents per MMBtu, based on an annualized royalty volume of
93,301,478 MMBtu (for NARM and 10 percent POOL reported sales type
codes).
 Annual Change in Royalties Due to Transportation Deduction Modification for Non-Arm's-Length Sales of Natural
 Gas
----------------------------------------------------------------------------------------------------------------
 Gulf of Mexico Other areas Total
----------------------------------------------------------------------------------------------------------------
Current Regulations Transport Deduction......................... $5,387,000 $16,375,000 $21,762,000
Estimate using new Transport Deduction.......................... 10,346,000 25,659,000 36,005,000
Difference...................................................... 4,959,000 9,284,000 14,243,000
Change per MMBtu................................................ 0.15 0.15 0.15
50% of lessees choose this option............................... .............. .............. 7,121,000
 -----------------------------------------------
 Net change in royalties as a result......................... .............. .............. (7,121,000)
----------------------------------------------------------------------------------------------------------------
Change in Royalties 4: Transportation Allowances in Excess of 50
Percent of the Royalty Value Prior to Allowances for Federal Gas
 In certain scenarios, a lessee may incur costs to transport Federal
gas at a cost that exceeds the regulatory limit of 50 percent of the
gas's royalty value prior to allowances. The proposed rule provides a
lessee the ability to request to exceed the 50 percent limit when the
lessee's costs above 50 percent are reasonable, actual, and necessary.
To estimate the change in royalties associated with the proposed
amendment, ONRR first identified all gas transportation allowances
reported on the monthly royalty reports exceeding the 50 percent limit
for calendar years 2014-2018. Next, ONRR calculated the transportation
allowance claimed for each royalty line compared to what the
transportation allowance would have been at the 50 percent limit. ONRR
then calculated annual totals and averaged them over 5 years. The
result is an annual decrease in royalties paid by industry of
approximately $279,000 per year.
Change in Royalties 5: Transportation Allowances in Excess of 50
Percent of the Royalty Value Prior to Allowances for Federal Oil
 As described in the section above, a lessee may incur costs to
transport Federal oil that exceed the regulatory limit of 50 percent of
the oil's royalty value prior to allowances. This proposed rule would
provide a lessee the ability to request to exceed that limit when the
lessee's actual costs are reasonable, actual, and necessary. To
estimate the change in royalties associated with this change, ONRR
first identified all oil transportation allowances reported on the
monthly royalty report that exceeded the 50 percent limit for calendar
years 2014-2018. As above, ONRR calculated the transportation allowance
claimed for each royalty line compared to what the transportation
allowance would have been at the 50 percent limit. ONRR then calculated
annual totals and averaged them over five years. The result was an
annual decrease in royalties paid by industry of approximately $11,000
per year.
Change in Royalties 6: Processing Allowances in Excess of 66\2/3\
Percent of the Royalty Value of Federal NGLs Prior to Allowances
 As with transportation allowances, a lessee may incur costs
required to process gas that exceed the regulatory limit of 66\2/3\
percent of the royalty value of the NGLs prior to allowances. The
proposed rule provides a lessee the ability to request to exceed that
limit when the lessee's costs above 66\2/3\ percent are reasonable,
actual, and necessary. To estimate the change in royalties associated
with this change, ONRR completed two separate calculations.
 First ONRR identified all NGL processing allowances reported on the
monthly royalty report that exceeded the 66\2/3\ percent limit for
calendar years 2014-2018. Next, ONRR calculated the processing
allowance claimed for each royalty line compared to what the processing
allowance would have been at the 66\2/3\ percent limit. ONRR then
calculated annual totals and averaged them over five years. The result
was an annual estimated decrease in royalties
[[Page 62067]]
paid by approximately $135,000 per year.
 ONRR also calculated and quantified the estimated impact for any
allowances above the 66\2/3\ percent limit for percentage of proceeds
(POP) contract sales. When POP sales are reported to ONRR, sales of gas
are reported where the value of the unprocessed gas is based on a
percentage of the proceeds the purchaser receives for the sales of the
processed gas plus the gas plant products attributed to the lessee's
production. Under the 2016 Valuation Rule, a lessee with a POP contract
is limited to 66\2/3\ percent of the royalty value prior to allowances
of the NGLs as a processing allowance even if its actual costs exceed
this limit. This proposed rule provides a lessee the ability to request
to exceed the 66\2/3\ percent limit for all processed gas contracts
when the lessee's costs are reasonable, actual, and necessary. 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 provides the processing
plant in the past cannot, when combined, exceed a value equivalent to
100 percent of the NGLs' value. Under the proposed rule, the combined
value of each product that a lessee gives up to the processing plant
could, with approval, exceed two thirds of the NGLs' value.
 Prior to the 2016 Valuation Rule, a lessee reported POP contracts
to ONRR using a sales type code that showed whether it was an arm's-
length (an APOP) or non-arm's-length (an NPOP) POP contract. Because
lessees reported APOP sales as unprocessed gas, there are no reported
processing allowances available for analysis, and ONRR cannot determine
the breakout between residue gas and NGLs. Lessees report residue gas
and NGLs separately for NPOPs. But NPOP volumes constitute only 0.04
percent of all the natural gas royalty volumes that lessees report to
ONRR. ONRR deemed the NPOP volume to be too low to adequately assess
the impact of this provision on both APOP and NPOP contracts. Thus,
ONRR examined the onshore residue gas and NGL royalty data reported for
calendar years 2014-2018 and assumed that lessees processed the gas and
paid royalties as if they sold the residue gas and NGLs under a POP
contract. First, ONRR averaged the total five-year residue gas and NGL
royalty values and assumed, based on typical agreement percentage
splits observed in compliance activities, that these royalties were
subject to a 70-percent POP contract. ONRR's compliance activities
indicate the typical POP contracts split is at a 70/30 percent
weighting retained percent of proceeds and cost of processing. ONRR
calculated 30 percent of both the value of residue gas and NGLs to
approximate a theoretical 30-percent processing deduction and then
compared the 30 percent total of residue gas and NGL values to 66\2/3\
percent of the NGL value (the maximum allowance under the current
regulations). The table below summarizes the calculations, rounded to
the nearest dollar:
 Pop Contract Allowance Threshold Determination
----------------------------------------------------------------------------------------------------------------
 5-year average
 royalty value 70% proceeds 30% processing
 prior to portion of POP cost portion of
 allowances contract POP contract
----------------------------------------------------------------------------------------------------------------
Residue Gas............................................ $765,199,287 $535,639,501 $229,559,786
NGLs................................................... 274,631,986 192,242,391 82,389,596
Total.................................................. 1,039,831,273 727,881,891 311,949,382
 -------------------------------------
66\2/3\ % Limit........................................ 183,087,991 (274,631,986 x \2/3\)
 -------------------------------------
Difference............................................. 128,861,391 ($311,949,382-$183,087,991)
----------------------------------------------------------------------------------------------------------------
 ONRR's analysis shows that, under the theoretical processing
allowance and POP contract, 30 percent of residue gas and NGLs ($312
million) would exceed the 66\2/3\ cap ($183 million). ONRR estimates
that this will reduce annual royalty payments by $9.8 million, which is
a transfer from the Federal, State, and local governments to industry.
ONRR determined this estimate by taking the royalty value exceeding the
POP contract allowance ($128.9 million) and dividing it by the annual
average non-POP volume (2,254,617,156 MMBtu) to calculate a per-MMBtu
rate of $0.06. ONRR then applied the $0.06 rate to the POP contract
total volume of 163,455,735 MMBtu to reach the $9.8 million estimate.
In this analysis, ONRR assumed all processing costs associated with the
30 percent assumption were allowable.
 Annual Change in Royalties for Requests To Exceed Allowance Threshold for POP Contracts
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
Annualized MMBtu Volume.................................. 2,254,617,156 ..................................
Rate/MMBtu over limit.................................... $0.06 ($128,861,391/2,254,617,156)
Annualized POP MMBtu Volume.............................. 163,455,735 ..................................
 ------------------------------------------------------
 Estimated Change in Royalties........................ ($9,807,000) ($.06 x 163,455,735)
----------------------------------------------------------------------------------------------------------------
 The total impact of both scenarios to allow processing allowances
in excess of 66\2/3\ percent results in an annual estimated decrease in
royalties of approximately $9.8 million.
Change in Royalties 7: Extraordinary Cost Gas Processing Allowances for
Federal Gas
 The proposed rule would allow a lessee to request an extraordinary
processing cost allowance. Using the approvals ONRR granted prior to
the 2016 Valuation Rule, we identified the 127 leases claiming an
extraordinary processing allowance for residue gas, sulfur, and
CO2 for calendar years 2014-2018. The total processing costs
are reported across all three products for these unique situations. For
these leases, we retrieved all Form ONRR-2014 lines with a processing
allowance reported by lessees. For CO2 and sulfur
[[Page 62068]]
produced from these leases, ONRR then calculated the annual average
processing allowances which exceeded the 66\2/3\ percent limit and
found that only two years in the analysis showed that the total
allowances exceeded the 66\2/3\-percent limit. Under these unique
exceptions, the processing allowances are also reported against residue
gas, so we also added the average annual processing allowances taken
for those same leases for residue gas. Based on these calculations,
ONRR estimates this change will result in a decrease in annual royalty
payments of approximately $11.1 million.
 Estimated Annual Change in Royalties Paid
------------------------------------------------------------------------

------------------------------------------------------------------------
Annual Average Sulfur allowances in excess of 66\2/3\%.. ($348,000)
Annual Average Residue Gas Allowance.................... (10,783,000)
Estimated Impact on Royalties........................... (11,131,000)
------------------------------------------------------------------------
Change in Royalties 8: Transportation Allowances for Deepwater
Gathering for Federal Oil and Gas
 The Deepwater Policy was in effect from 1999 until January 1, 2017
(the 2016 Valuation Rule's effective date). Under the Deepwater Policy,
ONRR allowed a lessee to treat certain expenses for subsea gathering as
transportation expenses and to deduct those costs from its royalty
payments. The 2016 Valuation Rule rescinded the Deepwater Policy. To
analyze the impact to industry of allowing the gathering costs to be
treated as deductible transportation costs, ONRR used data from the
Bureau of Safety and Environmental Enforcement's (BSEE's) Technical
Information Management System database to identify 113 current subsea
pipeline segments, and potentially 169 eligible leases, which may
qualify for an allowance under the Deepwater Policy. ONRR assumed that
all segments were similar (in other words, no adjustments were made to
account for the size, length, or type of pipeline) and considered only
the pipeline segments that were in active status and supporting leases
in producing status. To determine the range (shown in the tables at the
end of this section as low, mid, and high estimates) of changes to
royalties, ONRR estimates a 15 percent error rate in the identification
of the 113 eligible pipeline segments. This resulted in a range of 96
to 130 eligible pipeline segments. ONRR's audit data is available for
13 subsea gathering segments serving 15 leases covering time periods
from 1999 through 2010. ONRR used the data to determine an average
initial capital investment in the pipeline segments. ONRR used the
initial capital investment total to calculate depreciation and a return
on undepreciated capital investment (also known as the return on
investment or ROI) for eligible pipeline segments and calculated
depreciation using a 20-year straight-line depreciation schedule.
 ONRR calculated return on investment using the average BBB Bond
rate (the BBB Bond rating is a credit rating used by the Standard &
Poor's credit agency to signify a certain risk level of long-term bonds
and other investments) for January 2018. ONRR based the calculations
for depreciation and ROI on the first year a pipeline was in service.
From the same audit information, ONRR calculated an average annual
operating and maintenance (O&M) cost. ONRR increased the O&M cost by 12
percent to represent overhead expenses. ONRR then decreased the total
annual O&M cost per pipeline segment by nine percent because, on
average, nine percent of wellhead production volume is water. Water is
not royalty bearing, and a lessee may not take a deduction against non-
royalty-bearing fluids. Finally, ONRR used an average royalty rate of
14 percent, which is the volume-weighted-average royalty rate for the
non-Section 6 leases in the Gulf of Mexico. Based on these
calculations, the average annual allowance per pipeline segment is
approximately $256,000. This represents the estimated amount per
pipeline segment that ONRR would allow a lessee to take as a
transportation allowance based on the Deepwater Policy. To calculate a
range for the total cost, we multiplied the average annual allowance by
the low (96), mid (113), and high (130) number of eligible segments.
The low, mid, and high annual allowance estimates are $35 million,
$41.1 million, and $47.3 million, respectively.
 Of the eligible leases, 68 of 169, or about 40 percent, will
qualify for a deduction under the proposed amendment. But due to
varying lease terms, royalty relief programs, price thresholds, volume
thresholds, and other factors, ONRR estimated that half of the 68, or
32, leases eligible for royalty relief (20 percent of 169) have
received royalty relief. Thus, we decreased the low, mid, and high
annual cost-to-industry estimates by 20 percent. The table below shows
this section's estimated royalty impact.
 Annual Estimated Change in Royalties Allowing Deepwater Gathering
----------------------------------------------------------------------------------------------------------------
 Low Mid High
----------------------------------------------------------------------------------------------------------------
Royalty Impact...................................... ($30,500,000) ($35,900,000) ($41,300,000)
----------------------------------------------------------------------------------------------------------------
Cost 1 Transportation Allowances for Deepwater Gathering for Offshore
Federal Oil and Gas
 The proposed rule, by allowing transportation allowances for
deepwater gathering systems, will result in an administrative cost to
industry because it requires qualified lessees to monitor their costs
and perform calculations. The cost to perform this calculation is
significant because industry often hires outside consultants to
calculate their subsea transportation allowances. ONRR estimates that
each lessee with leases eligible for transportation allowances for
deepwater gathering systems will allocate one full-time employee
annually to perform the calculation. ONRR used data from the BLS to
estimate the hourly cost for industry accountants in a metropolitan
area [$42.39 mean hourly wage] with a multiplier of 1.4 for industry
benefits to equal approximately $59.35 per hour [$42.39 x 1.4 =
$59.35]. Using this fully-burdened labor cost per hour, ONRR estimates
that the annual administrative cost to industry would be approximately
$3.9 million.
[[Page 62069]]
 Annual Administrative Cost to Industry To Calculate Deepwater Transportation
----------------------------------------------------------------------------------------------------------------
 Annual burden Companies
 hours per Industry labor reporting Estimated cost
 company cost/hour eligible leases to industry
----------------------------------------------------------------------------------------------------------------
Deepwater Policy............................ 2,080 $59.35 32 $3,936,000
----------------------------------------------------------------------------------------------------------------
Cost Savings 1: Administrative Cost Savings From Using Index-Based
Valuation Option to Value Federal Unprocessed Gas, Residue Gas, Coalbed
Methane, and NGLs
 ONRR expects that industry will realize administrative-cost savings
if they choose to use the index-based valuation option to value
dispositions of Federal unprocessed gas, residue gas, coalbed methane,
and NGLs. A lessee will have price certainty when calculating its
royalties--saving time it currently spends on verifying gross proceeds.
ONRR estimates that 50 percent of lessees will use the index-based
valuation option. Further, ONRR estimates that it will shorten the time
burden per line reported by 50 percent (to 1.5 minutes per electronic
line submission and 3.5 minutes per manual line submission). As with
Cost 1, ONRR used tables from the Bureau of Labor Statistics to
estimate the fully-burdened hourly cost for an industry accountant in a
metropolitan area working in oil and gas extraction. The industry labor
cost factor for accountants would be approximately $59.35 per hour =
$42.39 [mean hourly wage] x 1.4 [benefits cost factor]. Using a labor
cost factor of $59.35 per hour, ONRR estimates the annual
administrative cost savings to industry will be approximately $1.4
million.
 Annual Administrative Cost Savings for Industry
----------------------------------------------------------------------------------------------------------------
 Estimated
 lines reported Annual burden
 Time burden per line reported using index hours
 option (50%)
----------------------------------------------------------------------------------------------------------------
Electronic Reporting (99%).................. 1.5 min........................... 892,620 22,315
Manual Reporting (1%)....................... 3.5 min........................... 9,016 526
Industry Labor Cost/hour.................... .................................. .............. $59.35
 -------------------------------------------------------------------
 Total Benefit to Industry............... .................................. .............. 1,356,000
----------------------------------------------------------------------------------------------------------------
Cost Savings 2: Administrative Cost Savings Using Index-Based Valuation
Option to Value Residue Gas and NGLs Simplifying Processing and
Transportation Cost Calculations
 ONRR expects industry will realize an additional one-time
administrative-cost savings if they choose to use the index-based
valuation option to value dispositions of Federal residue gas and NGLs,
as this method eliminates the need to unbundle and calculate specific
cost allocations related to processing and transportation. These cost
allocations, referred to as ``unbundling,'' are segregated portions of
a transportation or processing expense or fee attributable to placing
production in marketable condition. Industry would unbundle their
applicable plants and transportation systems one time in the absence of
this rule and then use those unbundled cost allocations for subsequent
royalty calculations. Industry is responsible for calculating these
costs, however ONRR has published and calculated a limited number of
unbundling cost allocations. In ONRR's experience, it takes
approximately 100 hours per gas plant. ONRR calculated the average
number of gas plants reported per payor is 3.4, across a total of 448
payors reporting residue gas and NGLs, between 2014-2018. Using the BLS
labor cost per hour of $59.35 (described above) and adjusting our
assumption to 50 percent of lessees choosing the index-based option, we
believe this results in a one-time cost savings to industry of $4.5
million dollars.
i. State and Local Governments
 ONRR estimates that the States and certain local governments this
rule impacts would receive an overall decrease in royalty share (which,
in part, was a reason for California's and New Mexico's challenges to
the 2017 Repeal Rule) based on the category the lease falls under,
including offshore Outer Continental Shelf Lands Act section 8(g)
leases (See 43 U.S.C. 1337(g)), Gulf of Mexico Energy Security Act
leases (GOMESA) ((43 U.S.C 1337(g))), and onshore Federal lands. ONRR
disburses royalties based on where the oil, gas, or coal was produced.
 Except for Federal Alaskan production (where Alaska receives 90
percent of the distribution), Section 8(g) leases in the OCS, and
qualified leases under GOMESA in the OCS (more information on
distribution percentages at https://revenuedata.doi.gov/how-it-works/gomesa/), the following distribution table generally applies:
 ONRR Disbursements by Area
------------------------------------------------------------------------
 Onshore Offshore
 % %
------------------------------------------------------------------------
Federal........................................... 51 95.2
State............................................. 49 4.8
------------------------------------------------------------------------
 Please visit https://revenuedata.doi.gov/explore/#federal-disbursements to find more information on ONRR's disbursements to any
specific State or local government.
 The next table in this section summarizes the State and local
government royalty decreases.
ii. Indian Lessors
 The provisions in the proposed rule are not expected to affect
Indian lessors.
iii. Federal Government
 The impact of the proposed rule to the Federal Government will be a
net decrease in royalty collections. ONRR estimates the net yearly
impact on the Federal Government (detailed in the next table of this
section) would be a loss of $32,239,000 in royalties.
[[Page 62070]]
iv. Summary of Royalty Impacts and Costs to Industry, State and Local
Governments, Indian Lessors, and the Federal Government
 In the table below, ONRR presents the net change in royalties by
rulemaking provision. Changes to royalties are neither costs nor
benefits, but transfers. The estimated changes in royalties assessed
will change both the private cost to the operator/lessee and the amount
of revenue collected by the Federal government and the States.
 Annual Economic Impacts for Industry, the Federal Government, and States
----------------------------------------------------------------------------------------------------------------
 Net change in Federal State
 Rule provision royalties proportion proportion
----------------------------------------------------------------------------------------------------------------
Index-Based Valuation Option Extended to Gas Dispositions....... $5,620,000 $3,606,000 $2,014,000
Index-Based Valuation Option Extended to NGL Dispositions....... 21,141,000 14,468,000 6,673,000
High to Midpoint Index Price for Non-Arm's-Length Gas (4,488,000) (2,880,000) (1,608,000)
 Dispositions...................................................
Transportation Deduction Non-Arm's-Length Index-Based Valuation (7,121,000) (4,569,000) (2,552,000)
 Option.........................................................
Gas Transportation Allowances................................... (279,000) (179,000) (100,000)
Oil Transportation Allowances................................... (11,000) (9,000) (2,000)
Gas Processing Allowances....................................... (9,942,000) (6,379,000) (3,563,000)
Extraordinary Processing Allowance.............................. (11,131,000) (7,142,000) (3,989,000)
Deepwater Policy................................................ (35,900,000) (29,155,000) (6,745,000)
 -----------------------------------------------
 Total....................................................... (42,111,000) (32,239,000) (9,872,000)
----------------------------------------------------------------------------------------------------------------
Note: totals may not add due to rounding.
2. Federal and Indian Coal
 ONRR estimates that there will be no economic impact in terms of
royalties to ONRR, Tribes, Individual Indian mineral owners, States, or
industry from the changes to coal valuation in this proposed rule. The
changes outlined in this proposed rule should result in coal values for
royalty purposes similar to those reported and paid to ONRR under the
regulations in effect since 1989. Further, as of this writing, lessees
have not submitted coal reporting under the 2016 Valuation Rule, so
ONRR lacks data showing any changes resulting from implementation of
the provisions of the 2016 Valuation Rule.
 ONRR requests your comments on the economic impact of the changes
listed below.
Change 1: Eliminate Reference to Default Provision Requirements for
Federal Oil and Gas
 ONRR proposed to remove the default provision from its regulations.
In instances of misconduct, breach of a lessee's duty to market, or
other situations where royalty value cannot be determined under the
rules, ONRR will use statutory authority to determine Federal oil and
gas royalty value under lease terms, FOGRMA, and other authorizing
legislation in the same manner--as ONRR would have prior to adoption of
the 2016 Valuation Rule. ONRR does not believe there is any overall
royalty impact from removing the default provision.
Change 2: Eliminating the Use of Arm's-Length Electricity Sales to
Value Non-Arm's-Length Dispositions of Federal Coal.
 In the 2016 Valuation Rule, ONRR estimated no impacts to industry
for this provision. Further, because lessees have not submitted
reporting under the 2016 Valuation Rule, ONRR lacks data showing any
changes that may have been attributable to this provision.
Change 3: Using the First Arm's- Length Sale to Value Non-Arm's-Length
Sales of Indian Coal
 ONRR did not estimate any impacts to industry for the proposed
change from this provision. Currently, lessees of Indian coal sell
their entire production at arm's length, so this proposed change would
have no royalty impact on lessees or lessors of Indian coal.
Change 4: Eliminating the Sales of Electricity to Value Non-Arm's-
Length Sales of Indian Coal
 ONRR did not estimate any impacts to industry for the proposed
change for this provision. Currently, lessees of Indian coal sell their
entire production at arm's-length so this proposed change would have no
royalty impact on lessees or lessors of Indian coal.
Change 5: Using First Arm's-Length Sale to Value Sales of Indian Coal
Between Parties That Lack Opposing Economic Interests.
 At the present time, all producers of Indian coal sell the produced
coal under arm's-length transactions. Accordingly, ONRR does not
anticipate any impact to royalty collections from the proposed change.
Change 6: Elimination of the Default Provision to Value Federal Oil,
Gas, and Coal and Indian Coal
 ONRR estimates that the royalty impact would be insignificant
because the default provision established a reasonable value of
production using market-based transaction data, which has always been,
and continues to be, the basis for ONRR's royalty valuation rules.
F. Public Comments
1. Federal Oil and Gas
 1. ONRR requests comments identifying the complexities industry
could avoid if an index-based valuation option were available for
arm's-length dispositions. Where it can be reasonably determined, ONRR
also requests comments quantifying the burden savings that an arm's-
length index-based valuation option would provide, in place of
reporting such dispositions using gross proceeds.
 2. ONRR requests comments specific to any unintentional burdens
that the 2016 Valuation Rule may have created by providing the index-
based valuation option to only the non-arm's-length dispositions for a
lessee with both arm's-length and non-arm's-length dispositions.
 3. ONRR also requests comments on whether the 2016 Valuation Rule's
separate arm's-length and non-arm's-length valuation methods impacted
lessee decision making on whether to use the index-based valuation
method for non-arm's-length dispositions.
 4. ONRR requests comments on alternatives that more closely match
values under the index-based valuation
[[Page 62071]]
method to the gross proceeds accruing under arm's-length dispositions
across all Federal oil and gas leases.
 5. ONRR requests comments on alternatives that would allow a lessee
and ONRR to establish a clear and consistent location to determine
royalty value under the index-based valuation options.
 6. ONRR is proposing to revise the transportation adjustment for
the OCS in the Gulf of Mexico to 10 percent per MMBtu, but not less
than 10 cents or more than 40 cents per MMBtu, and for all other areas
to 15 percent, but not less than 10 cents or more than 50 cents per
MMBtu. ONRR requests comments specific to whether the proposed change
accomplishes its purpose to more accurately reflect current
transportation costs. ONRR is also interested in comments that propose
alternative methods for calculating the transportation adjustment in a
timely matter, or that would avoid potentially iterative, controversial
rulemakings to update the adjustment.
 7. ONRR requests comments on the impacts of the 2016 Valuation
Rule's hard caps and the associated changes proposed in this rule.
Specifically, we are interested in any specific data commenters can
provide regarding the hard cap's effect on specific operations or other
lessee decision making and arguments that may be made for or against
the proposed change.
 8. ONRR is interested in receiving comments specific to how
codifying the Deepwater Policy would impact energy production and
exploration in the OCS now and in the future at depths of 200 meters or
deeper; how it would impact revenues to Federal, State, and local
governments; and feedback on any effects that could be anticipated on
non-OCS domestic production.
 9. ONRR requests comments on the following: (a) In what shallow
water situations is the Deepwater Policy currently applicable? (b) In
what shallow water situations would it be appropriate or inappropriate
to apply the Deepwater Policy in the future? (c) What criteria are
appropriate to evaluate when determining whether a shallow water lease
with a subsea completion should qualify for the deduction of gathering
costs as a transportation allowance? (d) Are there lessons to be
learned by how other leasing entities (e.g., State or private
landowners) manage such transportation allowances?
 10. ONRR requests comments on the following: (a) In what remote-
area situations is it uneconomic or unfeasible for a lessee to locate
separation, treatment, or royalty measurement functions on or near the
lease? (b) What criteria should ONRR use to distinguish between
traditional gathering, which generally occurs on or near the lease, and
the movement of bulk production in remote areas across lease boundaries
to a central separation, treatment, or royalty measurement facilities?
(c) How should ONRR distinguish between allowed and disallowed movement
in remote areas? (d) How should ONRR define ``remote area?'' (e) Is
there a way for ONRR to develop a coherent policy that distinguishes
between remote and non-remote areas in terms of allowing deduction of
certain costs to move bulk production? (f) If so, what are the
advantages and disadvantages of such an approach to lessees and to the
government (as resource owner)?
 11. ONRR requests comments on the following: (a) What terms ONRR
could use in place of ``misconduct'' to describe a lessee's activities
that would warrant ONRR establishing royalty value? (b) What specific
criteria ONRR could apply to distinguish when a lessee engaged in
``misconduct'' or the term replacing ``misconduct'' from a lessee's
mere clerical errors?
 12. ONRR requests comments on the following: (a) What criteria
could ONRR establish to provide lessees more clarity and certainty on
when ONRR would establish royalty value in place of typical methods?
(b) What factors and methods should ONRR consider when establishing
reasonable royalty values?
 13. Without a requirement to maintain signed contracts, ONRR
possesses broad authority to investigate and question the validity of
any contract. Therefore, ONRR requests comments specific to any
additional burdens the 2016 Valuation Rule's signature requirement
placed on lessees.
 14. ONRR proposes to eliminate the requirements under Sec. Sec.
1206.108(a)(5), 1206.148(a)(5), 1206.258(a)(5) and 1206.458(a)(5) for a
lessee to include citations to legal precedents when requesting a
valuation determination. ONRR requests comments on the burdens the
legal precedent requirement placed on industry, and any comments
related to the necessity of retaining the requirement.
 15. ONRR requests comments on how the proposed rule may or may not
fulfill its objective to implement Executive Orders and Secretarial
Orders. Moreover, ONRR looks to receive feedback on whether, and to
what extent, the proposed amendments would impact domestic energy
exploration and energy production, create economic opportunity, or
otherwise provide justification to alter--or not--transfer payments
between the United States and its lessees in the form of royalties.
2. Federal and Indian Coal
 1. ONRR is interested in receiving comments on alternatives that
could be used to value non-arm's-length coal sales and enable a lessee
to access the information needed to support royalty reporting while
ensuring the Federal and Indian lessors obtain fair market value for
the royalty share.
 2. ONRR also seeks input on whether the rules should be amended to
establish a minimum royalty value to protect the Federal or Indian
lessor's royalty share when production's value decreases between a
lease or mine and where the first arm's-length sale occurs. Commenters
are also encouraged to offer suggestions on the methodology to use to
establish a minimum royalty value.
 3. ONRR requests your comments on other appropriate alternatives to
simplify the method to determine royalty value for coal a lessee does
not sell at arm's-length, before its consumption or other disposition
as electricity.
 4. ONRR requests your comments on the economic impact of the
following: (a) Eliminating the use of arm's-length electricity sales to
value non-arm's-length dispositions of federal coal. (b) Using the
first arm's- length sale to value non-arm's-length sales of Indian
coal. (c) Eliminating the sales of electricity to value non-arm's-
length sales of Indian coal. (d) Using first arm's-length sale to value
sales of Indian coal between parties that lack opposing economic
interests. (e) Elimination of the default provision to value federal
oil, gas, and coal and Indian coal.
3. Civil Penalties
 1. ONRR proposes to amend Sec. 1241.70 to clarify that, for
payment violations only, ONRR would consider the consequence of the
unpaid, underpaid, or late payment amount when assessing a civil
penalty. ONRR requests comment on how this would impact lessees to
which ONRR issues a civil penalty.
 2. ONRR proposes to amend Sec. 1241.70 to clarify that ONRR may
consider aggravating and mitigating circumstances to increase or
decrease a penalty. ONRR requests comment on how this would impact
lessees subject to an ONRR-issued civil penalty. ONRR also seeks
comment on what facts or situations it should consider to be
aggravating and mitigating circumstances.
 3. ONRR seeks comment on how removing Sec. 1241.11(b)(5) would
affect lessees issued a civil penalty.
[[Page 62072]]
4. Other Matters
 ONRR requests comment on all other aspects of this proposed rule,
including (for instance) whether the proposed regulatory definition of
``Affiliate'' is too broad or too narrow in any respect. Commenters
should provide appropriate reasoning and factual support for all
contentions.
G. Statutory and Regulatory Review
1. Regulatory Planning and Review (Executive Orders 12866 and 13563)
 Summary of Proposed Changes to Oil & Gas Royalties Paid (Annual)
------------------------------------------------------------------------
 Net change in
 Rule provision royalties paid by
 lessees
------------------------------------------------------------------------
Index-Based Valuation Option Extended to Gas $5,620,000
 Dispositions........................................
Index-Based Valuation Option Extended to NGL 21,141,000
 Dispositions........................................
High to Midpoint Index Price for Non-Arm's-Length Gas (4,488,000)
 Dispositions........................................
Transportation Deduction Non-Arm's-Length Index-Based (7,121,000)
 Valuation Option....................................
Gas Transportation Allowances........................ (279,000)
Oil Transportation Allowances........................ (11,000)
Gas Processing Allowances............................ (9,942,000)
Extraordinary Processing Allowances.................. (11,131,000)
Deepwater Policy..................................... (35,900,000)
 ------------------
 Total............................................ (42,111,000)
------------------------------------------------------------------------
 Summary of Annual Adminstrative Impacts to Industry
------------------------------------------------------------------------
 Cost (cost
 Rule provision savings)
------------------------------------------------------------------------
Administrative Benefit for Index-Based Valuation ($1,356,000)
 Option for Gas & NGLs...............................
Administrative Cost for Deepwater Policy............. 3,936,000
 ------------------
 Total............................................ 2,580,000
------------------------------------------------------------------------
 One-Time Administrative Impacts to Industry
------------------------------------------------------------------------
 Rule Provision (Cost savings)
------------------------------------------------------------------------
Administrative Cost-savings in lieu of Unbundling ($4,520,000)
 related to Index-Based Valuation Option for Gas &
 NGLs...............................................
------------------------------------------------------------------------
 Executive Order 12866 provides that the Office of Information and
Regulatory Affairs (OIRA) of the Office of Management and Budget (OMB)
will review all significant rulemaking. OIRA has determined that the
proposed rule is significant.
 Executive Order 13563 reaffirms the principles of Executive Order
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. Executive Order 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.
2. Regulatory Flexibility Act
 The Department of the Interior certifies that the proposed rule
would not have a significant economic impact on a substantial number of
small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et
seq.). See above for the costs, benefits, and economic analysis.
 For the changes to 30 CFR part 1206, this rule would affect lessees
of Federal oil and gas leases. For the changes to 30 CFR part 1241,
this rule could affect violators of obligations under Federal and
Indian mineral 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 other Federal mineral leases to ONRR each month. Of these,
approximately 65 companies would be large businesses under the U.S.
Small Business Administration definition, because they would have more
than 500 employees. The Department estimates that the remaining 1,855
companies that this rule would affect are small businesses. In this
context, ONRR defines company size for lessees as follows; large:
Average annual royalties over $100 million, medium: $99-$10 million,
and small: Less than $10 million.
 As stated in the Summary of Royalty Impacts and Costs table, shown
above, this rule would benefit industry through a cost savings of
approximately $42 million per year. Small businesses account for about
8 percent of the royalties. Applying that percentage to industry costs,
we estimate that the changes in the proposed rule would result in a
cost savings to small-business lessees by a total of approximately $3.5
million per year, which shared between
[[Page 62073]]
the 1,855 companies totals in an average $1,887 cost savings per
company. The amount would vary for each company depending on the volume
of production that the small business produces and sells each year.
 In sum, we do not estimate that this rule would result in a
significant economic impact on a substantial number of small entities
because this rule does not impose new costs on the regulated industry
anywhere where those entities would not have an opportunity to realize
some cost savings. Each small entity would consider the provisions to
decide whether it is economically advantageous to incur increases in
administrative costs to achieve the cost savings the provision would
provide. The rule would benefit affected small businesses a collective
total of $3.5 million per year. Thus, an Initial Regulatory Flexibility
Act Analysis is not required, and, accordingly, a Small Entity
Compliance Guide is not required.
 Your comments are important. The Small Business and Agriculture
Regulatory Enforcement Ombudsman and ten Regional Fairness Boards
receive comments from small businesses about Federal agency enforcement
actions. The Ombudsman annually evaluates the enforcement activities
and rates each agency's responsiveness to small business. If you wish
to comment on ONRR's actions, call 1-(888) 734-3247. You may comment to
the Small Business Administration without fear of retaliation.
Allegations of discrimination/retaliation filed with the Small Business
Administration would be investigated for appropriate action.
3. Small Business Regulatory Enforcement Fairness Act
 The proposed rule is not a major rule under 5 U.S.C. 804(2), the
Small Business Regulatory Enforcement Fairness Act. This rule:
 a. Will not have an annual effect on the economy of $100 million or
more. We estimate that the cumulative effect on all of industry will be
a reduction in private cost of nearly $39.52 million per year, which is
the sum of $42.1 million in decreased royalty payments and $2.58
million in additional costs due to increased administrative burdens.
The net change in royalty payments is a transfer rather than a cost or
cost savings. The Summary of Royalty Impacts and Costs table, as shown
above, demonstrates that the cumulative economic impact on industry,
State and local governments, and the Federal Government will be well
below the $100 million threshold that the Federal Government uses to
define a rule as having a significant impact on the economy.
 b. Will not cause a major increase in costs or prices for
consumers, individual industries, Federal, State, or local government
agencies, or geographic regions. See above.
 c. Will not have significant adverse effects on competition,
employment, investment, productivity, innovation, or the ability of
United States-based enterprises to compete with foreign-based
enterprises. The proposed rule would benefit United States-based
enterprises. We are the only agency that promulgates rules for royalty
valuation on Federal oil and gas leases and Federal and Indian coal
leases.
4. Unfunded Mandates Reform Act
 The proposed rule would not impose an unfunded mandate on State,
local, or Tribal governments, or the private sector of more than $100
million per year. This rule will 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 because this rule is not an unfunded mandate.
5. Takings (Executive Order 12630)
 Under the criteria in section 2 of Executive Order 12630, the
proposed rule would not have any significant takings implications. This
rule would not impose conditions or limitations on the use of any
private property. This rule would apply to the valuation of Federal oil
and gas and Federal and Indian coal only. The proposed rule would only
make minor technical changes to ONRR's civil penalty regulations that
have no expected economic impact. The proposed rule would not require a
takings implication assessment.
6. Federalism (Executive Order 13132)
 Under the criteria in section 1 of Executive Order 13132, the
proposed rule would not have sufficient Federalism implications to
warrant the preparation of a Federalism summary impact statement. The
management of Federal oil and gas is the responsibility of the
Secretary of the Interior, and ONRR distributes all of the royalties
that we collect under Federal oil and gas leases as specified in the
relevant disbursement statutes. This rule will not impose
administrative costs on States or local governments. This rule also
will not substantially and directly affect the relationship between the
Federal and State governments. Because this rule will not alter that
relationship, it does not require a Federalism summary impact
statement.
7. Civil Justice Reform (Executive Order 12988)
 The proposed rule complies with the requirements of Executive Order
12988. Specifically, this rule:
 a. Will meet the criteria of Section 3(a), which requires that we
review all regulations to eliminate errors and ambiguity and write them
to minimize litigation.
 b. Will meet the criteria of Section 3(b)(2), which requires that
we write all regulations in clear language using clear legal standards.
8. Consultation With Indian Tribal Governments (Executive Order 13175)
 Under the criteria in Executive Order 13175, ONRR evaluated the
proposed rule and determined that it will not substantially affect
Federally recognized Indian tribes. The proposed rule only affects
Federal, not Indian, oil and gas leases. For Indian coal leases, ONRR
estimated that the proposed rule would not alter the royalty valuation
of Indian coal.
9. Paperwork Reduction Act
 The proposed rule:
 (a) Will not contain any new information collection requirements.
 (b) Will not require a submission to OMB under the Paperwork
Reduction Act of 1995 (44 U.S.C. 3501 et seq.). See 5 CFR 1320.4(a)(2).
 The proposed rule will leave intact the information collection
requirements that OMB has already approved under OMB Control Numbers
1012-0004, 1012-0005, and 1012-0010.
10. National Environmental Policy Act
 This rule does not constitute a major Federal action significantly
affecting the quality of the human environment. ONRR is not required to
provide a detailed statement under the National Environmental Policy
Act of 1969 (NEPA) because this rule qualifies for a categorical
exclusion under 43 CFR 46.210(c) and (i) and the Department of the
Interior's Departmental Manual, part 516, section 15.4.D: ``(c) Routine
financial transactions including such things as . . . audits, fees,
bonds, and royalties . . . [and] (i) [p]olicies, directives,
regulations, and guidelines . . . [t]hat are of an administrative,
financial, legal, technical, or procedural nature.'' ONRR also
determined that this rule is not involved in any of the extraordinary
circumstances listed in 43 CFR 46.215 that require further analysis
[[Page 62074]]
under NEPA. The changes resulting from the proposed amendments will
have no consequence on the physical environment. The proposed rule does
not alter, in any material way, natural resources exploration,
production, or transportation.
11. Effects on the Energy Supply (Executive Order 13211)
 The proposed rule is not a significant energy action under the
definition in Executive Order 13211, and, therefore, does not require a
statement of energy effects.
12. Clarity of This Regulation
 Executive Orders 12866 (section 1(b)(12)), 12988 (section
3(b)(1)(B)), and 13563 (section 1(a)), and the Presidential Memorandum
of June 1, 1998, require us to write all rules in plain language. This
means that the rules we publish must use:
 (a) Logical organization.
 (b) Active voice to address readers directly.
 (c) Clear language rather than jargon.
 (d) Short sections and sentences.
 (e) Lists and tables wherever possible.
 If you feel that ONRR has not met these requirements, send your
comments to [email protected]. To better help ONRR understand your
comments, please make your comments as specific as possible. For
example, you should tell ONRR the numbers of the sections or paragraphs
that you think were written unclearly, which sections or sentences are
too long, the sections where you feel lists or tables would be useful.
13. Public Availability of Comments
 ONRR will post all comments we receive, including a respondent's
name and address. Before including your address, phone number, email
address, or other personal identifying information in your comment, you
should be aware that your entire comment, including your personal
identifying information, may be made publicly available at any time.
While you can ask, in your comment, that your personal identifying
information be withheld from public view, ONRR cannot guarantee that we
will be able to do so.
List of Subjects
30 CFR Part 1206
 Coal, Continental shelf, Geothermal energy, Government contracts,
Indians--lands, Mineral royalties, Oil and gas exploration, Public
lands--mineral resources, Reporting and recordkeeping requirements
30 CFR Part 1241
 Administrative practice and procedure, Coal, Indians--lands,
Mineral royalties, Natural gas, Oil and gas exploration, Penalties,
Public lands--mineral resources.
Kimbra G. Davis,
Director for Office of Natural Resources Revenue.
Authority and Issuance
 For the reasons discussed in the preamble, the Office of Natural
Resources Revenue proposes to amend 30 CFR parts 1206 and 1241 as set
forth below:
PART 1206--PRODUCT VALUATION
0
1. 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.
Subpart A--General Provisions and Definitions
0
2. Revise Sec. 1206.20 to read as follows:
Sec. 1206.20 What definitions apply to this part?
 The following definitions apply to this part:
 Ad valorem lease means a lease where the royalty due to the lessor
is based upon a percentage of the amount or value of the coal.
 Affiliate means a person who controls, is controlled by, or is
under common control with another person. For the purposes of this
subpart:
 (1) Ownership or common ownership of more than 50 percent of the
voting securities, or instruments of ownership or other forms of
ownership, of another person constitutes control. Ownership of less
than 10 percent constitutes a presumption of non-control that ONRR may
rebut.
 (2) If there is ownership or common ownership of 10 through 50
percent of the voting securities or instruments of ownership, or other
forms of ownership, of another person, ONRR will consider each of the
following factors to determine if there is control under the
circumstances of a particular case:
 (i) The extent to which there are common officers or directors
 (ii) With respect to the voting securities, or instruments of
ownership or other forms of ownership: The percentage of ownership or
common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons,
if a person is the greatest single owner, or if there is an opposing
voting bloc of greater ownership
 (iii) Operation of a lease, plant, pipeline, or other facility
 (iv) The extent of other owners' participation in operations and
day-to-day management of a lease, plant, or other facility
 (v) Other evidence of power to exercise control over or common
control with another person
 (3) Regardless of any percentage of ownership or common ownership,
relatives, either by blood or marriage, are affiliates.
 ANS means Alaska North Slope.
 Area means a geographic region at least as large as the limits of
an oil and/or gas field, in which oil and/or gas lease products have
similar quality and economic characteristics. Area boundaries are not
officially designated and the areas are not necessarily named.
 Arm's-length-contract means a contract or agreement between
independent persons who are not affiliates and who have opposing
economic interests regarding that contract. To be considered arm's-
length for any production month, a contract must satisfy this
definition for that month, as well as when the contract was executed.
 Audit means an examination, conducted under the generally accepted
Governmental Auditing Standards, of royalty reporting and payment
compliance activities of lessees, designees or other persons who pay
royalties, rents, or bonuses on Federal leases or Indian leases.
 BIA means the Bureau of Indian Affairs of the Department of the
Interior.
 BLM means the Bureau of Land Management of the Department of the
Interior.
 BOEM means the Bureau of Ocean Energy Management of the Department
of the Interior.
 BSEE means the Bureau of Safety and Environmental Enforcement of
the Department of the Interior.
 Coal means coal of all ranks from lignite through anthracite.
 Coal washing means any treatment to remove impurities from coal.
Coal washing may include, but is not limited to, operations, such as
flotation, air, water, or heavy media separation; drying; and related
handling (or combination thereof).
 Compression means the process of raising the pressure of gas.
 Condensate means liquid hydrocarbons (normally exceeding 40 degrees
of API gravity) recovered at the surface without processing. Condensate
[[Page 62075]]
is the mixture of liquid hydrocarbons resulting from condensation of
petroleum hydrocarbons existing initially in a gaseous phase in an
underground reservoir.
 Constraint means a reduction in, or elimination of, gas flow,
deliveries, or sales required by the delivery system.
 Contract means any oral or written agreement, including amendments
or revisions, between two or more persons, that is enforceable by law
and that, with due consideration, creates an obligation.
 Designee means the person whom the lessee designates to report and
pay the lessee's royalties for a lease.
 Exchange agreement means an agreement where one person agrees to
deliver oil to another person at a specified location in exchange for
oil deliveries at another location. Exchange agreements may or may not
specify prices for the oil involved. They frequently specify dollar
amounts reflecting location, quality, or other differentials. Exchange
agreements include buy/sell agreements, which specify prices to be paid
at each exchange point and may appear to be two separate sales within
the same agreement. Examples of other types of exchange agreements
include, but are not limited to, exchanges of produced oil for specific
types of crude oil (such as West Texas Intermediate); exchanges of
produced oil for other crude oil at other locations (Location Trades);
exchanges of produced oil for other grades of oil (Grade Trades); and
multi-party exchanges.
 FERC means Federal Energy Regulatory Commission.
 Field means a geographic region situated over one or more
subsurface oil and gas reservoirs and encompassing at least the
outermost boundaries of all oil and gas accumulations known within
those reservoirs, vertically projected to the land surface. State oil
and gas regulatory agencies usually name onshore fields and designate
their official boundaries. BOEM names and designates boundaries of OCS
fields.
 Gas means any fluid, either combustible or non-combustible,
hydrocarbon or non-hydrocarbon, which is extracted from a reservoir and
which has neither independent shape nor volume, but tends to expand
indefinitely. It is a substance that exists in a gaseous or rarefied
state under standard temperature and pressure conditions.
 Gas plant products means separate marketable elements, compounds,
or mixtures, whether in liquid, gaseous, or solid form, resulting from
processing gas, excluding residue gas.
 Gathering means the movement of lease production to a central
accumulation or treatment point on the lease, unit, or communitized
area, or to a central accumulation or treatment point off of the lease,
unit, or communitized area that BLM or BSEE approves for onshore and
offshore leases, respectively. Excluded from this definition is the
movement of bulk production from a wellhead to an offshore platform
which may, for valuation purposes, be considered a function for which a
Transportation Allowance is properly taken pursuant to Sec.
1206.110(a)(1).
 Geographic region means, for Federal gas, an area at least as large
as the defined limits of an oil and or gas field in which oil and/or
gas lease products have similar quality and economic characteristics.
 Gross proceeds means the total monies and other consideration
accruing for the disposition of any of the following:
 (1) Oil. Gross proceeds also include, but are not limited to, the
following examples:
 (i) Payments for services such as dehydration, marketing,
measurement, or gathering which the lessee must perform at no cost to
the Federal Government
 (ii) The value of services, such as salt water disposal, that the
producer normally performs but that the buyer performs on the
producer's behalf
 (iii) Reimbursements for harboring or terminalling fees, royalties,
and any other reimbursements
 (iv) Tax reimbursements, even though the Federal royalty interest
may be exempt from taxation
 (v) Payments made to reduce or buy down the purchase price of oil
produced in later periods by allocating such payments over the
production whose price that the payment reduces and including the
allocated amounts as proceeds for the production as it occurs
 (vi) Monies and all other consideration to which a seller is
contractually or legally entitled but does not seek to collect through
reasonable efforts
 (2) Gas, residue gas, and gas plant products. Gross proceeds also
include, but are not limited to, the following examples:
 (i) Payments for services such as dehydration, marketing,
measurement, or gathering that the lessee must perform at no cost to
the Federal Government
 (ii) Reimbursements for royalties, fees, and any other
reimbursements
 (iii) Tax reimbursements, even though the Federal royalty interest
may be exempt from taxation
 (iv) Monies and all other consideration to which a seller is
contractually or legally entitled, but does not seek to collect through
reasonable efforts
 (3) Coal. Gross proceeds also include, but are not limited to, the
following examples:
 (i) Payments for services such as crushing, sizing, screening,
storing, mixing, loading, treatment with substances including chemicals
or oil, and other preparation of the coal that the lessee must perform
at no cost to the Federal Government or Indian lessor
 (ii) Reimbursements for royalties, fees, and any other
reimbursements
 (iii) Tax reimbursements even though the Federal or Indian royalty
interest may be exempt from taxation
 (iv) Monies and all other consideration to which a seller is
contractually or legally entitled, but does not seek to collect through
reasonable efforts
 Index means:
 (1) For gas, the calculated composite price ($/MMBtu) of spot
market sales that a publication that meets ONRR-established criteria
for acceptability at the index pricing point publishes
 (2) For oil, the calculated composite price ($/barrel) of spot
market sales that a publication that meets ONRR-established criteria
for acceptability at the index pricing point publishes.
 Index pricing point means any point on a pipeline for which there
is an index, which ONRR-approved publications may refer to as a trading
location.
 Index zone means a field or an area with an active spot market and
published indices applicable to that field or an area that is
acceptable to ONRR under Sec. 1206.141(d)(1).
 Indian Tribe means any Indian Tribe, band, nation, pueblo,
community, rancheria, colony, or other group of Indians for which any
minerals or interest in minerals is held in trust by the United States
or is subject to Federal restriction against alienation.
 Individual Indian mineral owner means any Indian for whom minerals
or an interest in minerals is held in trust by the United States or who
holds title subject to Federal restriction against alienation.
 Keepwhole contract means a processing agreement under which the
processor delivers to the lessee a quantity of gas after processing
equivalent to the quantity of gas that the processor received from the
lessee prior to processing, normally based on heat
[[Page 62076]]
content, less gas used as plant fuel and gas unaccounted for and/or
lost. This includes, but is not limited to, agreements under which the
processor retains all NGLs that it recovered from the lessee's gas.
 Lease means any contract, profit-sharing arrangement, joint
venture, or other agreement issued or approved by the United States
under any mineral leasing law, including the Indian Mineral Development
Act, 25 U.S.C. 2101-2108, that authorizes exploration for, extraction
of, or removal of lease products. Depending on the context, lease may
also refer to the land area that the authorization covers.
 Lease products mean any leased minerals, attributable to,
originating from, or allocated to a lease or produced in association
with a lease.
 Lessee means any person to whom the United States, an Indian Tribe,
and/or Individual Indian mineral owner issues a lease, and any person
who has been assigned all or a part of record title, operating rights,
or an obligation to make royalty or other payments required by the
lease. Lessee includes:
 (1) Any person who has an interest in a lease.
 (2) In the case of leases for Indian coal or Federal coal, an
operator, payor, or other person with no lease interest who makes
royalty payments on the lessee's behalf.
 Like quality means similar chemical and physical characteristics.
 Location differential means an amount paid or received (whether in
money or in barrels of oil) under an exchange agreement that results
from differences in location between oil delivered in exchange and oil
received in the exchange. A location differential may represent all or
part of the difference between the price received for oil delivered and
the price paid for oil received under a buy/sell exchange agreement.
 Market center means a major point that ONRR recognizes for oil
sales, refining, or transshipment. Market centers generally are
locations where ONRR-approved publications publish oil spot prices.
 Marketable condition means lease products which are sufficiently
free from impurities and otherwise in a condition that they will be
accepted by a purchaser under a sales contract typical for the field or
area for Federal oil and gas, and region for Federal and Indian coal.
 Mine means an underground or surface excavation or series of
excavations and the surface or underground support facilities that
contribute directly or indirectly to mining, production, preparation,
and handling of lease products.
 Net output means the quantity of:
 (1) For gas, residue gas and each gas plant product that a
processing plant produces.
 (2) For coal, the quantity of washed coal that a coal wash plant
produces.
 Netting means reducing the reported sales value to account for an
allowance instead of reporting the allowance as a separate entry on the
Report of Sales and Royalty Remittance (Form ONRR-2014) or the Solid
Minerals Production and Royalty Report (Form ONRR-4430).
 NGLs means Natural Gas Liquids.
 NYMEX price means the average of the New York Mercantile Exchange
(NYMEX) settlement prices for light sweet crude oil delivered at
Cushing, Oklahoma, calculated as follows:
 (1) First, sum the prices published for each day during the
calendar month of production (excluding weekends and holidays) for oil
to be delivered in the prompt month corresponding to each such day.
 (2) Second, divide the sum by the number of days on which those
prices are published (excluding weekends and holidays).
 Oil means a mixture of hydrocarbons that existed in the liquid
phase in natural underground reservoirs, remains liquid at atmospheric
pressure after passing through surface separating facilities, and is
marketed or used as a liquid. Condensate recovered in lease separators
or field facilities is oil.
 ONRR means the Office of Natural Resources Revenue of the
Department of the Interior.
 ONRR-approved commercial price bulletin means a publication that
ONRR approves for determining NGLs prices.
 ONRR-approved publication means:
 (1) For oil, a publication that ONRR approves for determining ANS
spot prices or WTI differentials.
 (2) For gas, a publication that ONRR approves for determining index
pricing points.
 Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters, as
defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301), and
of which the subsoil and seabed appertain to the United States and are
subject to its jurisdiction and control.
 Payor means any person who reports and pays royalties under a
lease, regardless of whether that person also is a lessee.
 Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
 Processing means any process designed to remove elements or
compounds (hydrocarbon and non-hydrocarbon) from gas, including
absorption, adsorption, or refrigeration. Field processes which
normally take place on or near the lease, such as natural pressure
reduction, mechanical separation, heating, cooling, dehydration, and
compression, are not considered processing. The changing of pressures
and/or temperatures in a reservoir is not considered processing. The
use of a Joule-Thomson (JT) unit to remove NGLs from gas is considered
processing regardless of where the JT unit is located, provided that
you market the NGLs as NGLs.
 Processing allowance means a deduction in determining royalty value
for the reasonable, actual costs the lessee incurs for processing gas.
 Prompt month means the nearest month of delivery for which NYMEX
futures prices are published during the trading month.
 Quality differential means an amount paid or received under an
exchange agreement (whether in money or in barrels of oil) that results
from differences in API gravity, sulfur content, viscosity, metals
content, and other quality factors between oil delivered and oil
received in the exchange. A quality differential may represent all or
part of the difference between the price received for oil delivered and
the price paid for oil received under a buy/sell agreement.
 Region for coal means the eight Federal coal production regions,
which the Bureau of Land Management designates as follows: Denver-Raton
Mesa Region, Fort Union Region, Green River-Hams Fork Region, Powder
River Region, San Juan River Region, Southern Appalachian Region,
Uinta-Southwestern Utah Region, and Western Interior Region. See 44 FR
65197 (1979).
 Residue gas means that hydrocarbon gas consisting principally of
methane resulting from processing gas.
 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
[[Page 62077]]
published for each day during the trading month for which the month of
production is the prompt month; P1 = the average of the
daily NYMEX settlement prices for deliveries during the month following
the month of production, published for each day during the trading
month for which the month of production is the prompt month; and
P2 = the average of the daily NYMEX settlement prices for
deliveries during the second month following the month of production,
as published for each day during the trading month for which the month
of production is the prompt month. Calculate the average of the daily
NYMEX settlement prices using only the days on which such prices are
published (excluding weekends and holidays).
 (1) Example 1. Prices in Out Months are Lower Going Forward: The
month of production for which you must determine royalty value is
December. December was the prompt month (for year 2011) from October 21
through November 18. January was the first month following the month of
production, and February was the second month following the month of
production. P0 therefore, is the average of the daily NYMEX
settlement prices for deliveries during December published for each
business day between October 21 and November 18. P1 is the
average of the daily NYMEX settlement prices for deliveries during
January published for each business day between October 21 and November
18. P2 is the average of the daily NYMEX settlement prices
for deliveries during February published for each business day between
October 21 and November 18. In this example, assume that P0
= $95.08 per bbl, P1 = $95.03 per bbl, and P2 =
$94.93 per bbl. In this example (a declining market), Roll = .6667 x
($95.08-$95.03) + .3333 x ($95.08-$94.93) = $0.03 + $0.05 = $0.08. You
add this number to the NYMEX price.
 (2) Example 2. Prices in Out Months are Higher Going Forward: The
month of production for which you must determine royalty value is
November. November was the prompt month (for year 2012) from September
21 through October 22. December was the first month following the month
of production, and January was the second month following the month of
production. P0 therefore, is the average of the daily NYMEX
settlement prices for deliveries during November published for each
business day between September 21 and October 22. P1 is the
average of the daily NYMEX settlement prices for deliveries during
December published for each business day between September 21 and
October 22. P2 is the average of the daily NYMEX settlement
prices for deliveries during January published for each business day
between September 21 and October 22. In this example, assume that
P0 = $91.28 per bbl, P1 = $91.65 per bbl, and
P2 = $92.10 per bbl. In this example (a rising market), Roll
= .6667 x ($91.28-$91.65) + .3333 x ($91.28-$92.10) = (-$0.25) + (-
$0.27) = (-$0.52). You add this negative number to the NYMEX price
(effectively, a subtraction from the NYMEX price).
 Sale means a contract between two persons where:
 (1) The seller unconditionally transfers title to the oil, gas, gas
plant product, or coal to the buyer and does not retain any related
rights, such as the right to buy back similar quantities of oil, gas,
gas plant product, or coal from the buyer elsewhere;
 (2) The buyer pays money or other consideration for the oil, gas,
gas plant product, or coal; and
 (3) The parties' intent is for a sale of the oil, gas, gas plant
product, or coal to occur.
 Section 6 lease means an OCS lease subject to section 6 of the
Outer Continental Shelf Lands Act, as amended, 43 U.S.C. 1335.
 Short ton means 2,000 pounds.
 Spot price means the price under a spot sales contract where:
 (1) A seller agrees to sell to a buyer a specified amount of oil at
a specified price over a specified period of short duration.
 (2) No cancellation notice is required to terminate the sales
agreement.
 (3) There is no obligation or implied intent to continue to sell in
subsequent periods.
 Tonnage means tons of coal measured in short tons.
 Trading month means the period extending from the second business
day before the 25th day of the second calendar month preceding the
delivery month (or, if the 25th day of that month is a non-business
day, the second business day before the last business day preceding the
25th day of that month) through the third business day before the 25th
day of the calendar month preceding the delivery month (or, if the 25th
day of that month is a non-business day, the third business day before
the last business day preceding the 25th day of that month), unless the
NYMEX publishes a different definition or different dates on its
official website, www.cmegroup.com, in which case, the NYMEX definition
will apply.
 Transportation allowance means a deduction in determining royalty
value for the reasonable, actual costs that the lessee incurs for
moving:
 (1) Oil to a point of sale or delivery off of the lease, unit area,
or communitized area. The transportation allowance does not include
gathering costs.
 (2) Unprocessed gas, residue gas, or gas plant products to a point
of sale or delivery off of the lease, unit area, or communitized area,
or away from a processing plant. The transportation allowance does not
include gathering costs.
 (3) Coal to a point of sale remote from both the lease and mine or
wash plant.
 Washing allowance means a deduction in determining royalty value
for the reasonable, actual costs the lessee incurs for coal washing.
 WTI differential means the average of the daily mean differentials
for location and quality between a grade of crude oil at a market
center and West Texas Intermediate (WTI) crude oil at Cushing published
for each day for which price publications perform surveys for
deliveries during the production month, calculated over the number of
days on which those differentials are published (excluding weekends and
holidays). Calculate the daily mean differentials by averaging the
daily high and low differentials for the month in the selected
publication. Use only the days and corresponding differentials for
which such differentials are published.
Subpart C--Federal Oil
0
3. Revise Sec. 1206.101 to read as follows:
Sec. 1206.101 How do I calculate royalty value for oil I or my
affiliate sell(s) under an arm's-length contract?
 (a) The value of oil under this section for royalty purposes is the
gross proceeds accruing to you or your affiliate under the arm's-length
contract less applicable allowances determined under Sec. 1206.111 or
1206.112. This value does not apply if you exercise an option to use a
different value provided in paragraph (c)(1) or (c)(2)(i) of this
section, or if one of the exceptions in paragraph (d) of this section
applies. You must use this paragraph (a) to value oil when:
 (1) You sell under an arm's-length sales contract; or
 (2) You sell or transfer to your affiliate or another person under
a non-arm's-length contract and that affiliate or person, or another
affiliate of either of them, then sells the oil under an arm's-length
contract, unless you exercise the
[[Page 62078]]
option provided in paragraph (c)(2)(i) of this section.
 (b) If you have multiple arm's-length contracts to sell oil
produced from a lease that is valued under paragraph (a) of this
section, the value of the oil is the volume-weighted average of the
values established under this section for each contract for the sale of
oil produced from that lease.
 (c)(1) If you enter into an arm's-length exchange agreement, or
multiple sequential arm's-length exchange agreements, and following the
exchange(s) that you or your affiliate sell(s) the oil received in the
exchange(s) under an arm's-length contract, then you may use either
paragraph (a) of this section or Sec. 1206.102 to value your
production for royalty purposes. If you fail to make the election
required under this paragraph, you may not make a retroactive election.
 (i) If you use paragraph (a) of this section, your gross proceeds
are the gross proceeds under your or your affiliate's arm's-length
sales contract after the exchange(s) occur(s). You must adjust your
gross proceeds for any location or quality differential, or other
adjustments, that you received or paid under the arm's-length exchange
agreement(s). If ONRR determines that any arm's-length exchange
agreement does not reflect reasonable location or quality
differentials, ONRR may require you to value the oil under Sec.
1206.102. You may not otherwise use the price or differential specified
in an arm's-length exchange agreement to value your production.
 (ii) When you elect under Sec. 1206.101(c)(1) to use paragraph (a)
of this section or Sec. 1206.102, you must make the same election for
all of your production from the same unit, communitization agreement,
or lease (if the lease is not part of a unit or communitization
agreement) sold under arm's-length contracts following arm's-length
exchange agreements. You may not change your election more often than
once every two years.
 (2)(i) If you sell or transfer your oil production to your
affiliate, and that affiliate or another affiliate then sells the oil
under an arm's-length contract, you may use either paragraph (a) of
this section or Sec. 1206.102 to value your production for royalty
purposes.
 (ii) When you elect under paragraph (c)(2)(i) of this section to
use paragraph (a) of this section or Sec. 1206.102, you must make the
same election for all of your production from the same unit,
communitization agreement, or lease (if the lease is not part of a unit
or communitization agreement) that your affiliates resell at arm's-
length. You may not change your election more often than once every two
years.
 (d) 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. 1206.102 or at the total consideration
received.
 (2) You must value the oil under Sec. 1206.102 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.
0
4. Revise Sec. 1206.102 to read as follows:
Sec. 1206.102 How do I value oil not sold under an arm's-length
contract?
 This section explains how to value oil that you may not value under
Sec. 1206.101 or that you elect under Sec. 1206.101(c)(1) to value
under this section. First, determine if paragraph (a), (b), or (c) of
this section applies to production from your lease, or if you may apply
paragraph (d) or (e) with ONRR's approval.
 (a) Production from leases in California or Alaska. Value is the
average of the daily mean ANS spot prices published in any ONRR-
approved publication during the trading month most concurrent with the
production month. For example, if the production month is June,
calculate the average of the daily mean prices using the daily ANS spot
prices published in the ONRR-approved publication for all of the
business days in June.
 (1) To calculate the daily mean spot price, you must average the
daily high and low prices for the month in the selected publication.
 (2) You must use only the days and corresponding spot prices for
which such prices are published.
 (3) You must adjust the value for applicable location and quality
differentials, and you may adjust it for transportation costs, under
Sec. 1206.111.
 (4) After you select an ONRR-approved publication, you may not
select a different publication more often than once every two years,
unless the publication you use is no longer published or ONRR revokes
its approval of the publication. If you must change publications, you
must begin a new two-year period.
 (b) Production from leases in the Rocky Mountain Region. This
paragraph provides methods and options for valuing your production
under different factual situations. You must consistently apply
paragraph (b)(2) or (3) of this section to value all of your production
from the same unit, communitization agreement, or lease (if the lease
or a portion of the lease is not part of a unit or communitization
agreement) that you cannot value under Sec. 1206.101 or that you elect
under Sec. 1206.101(c)(1) to value under this section.
 (1) You may elect to value your oil under either paragraph (b)(2)
or (3) of this section. After you select either paragraph (b)(2) or (3)
of this section, you may not change to the other method more often than
once every two years, unless the method you have been using is no
longer applicable and you must apply the other paragraph. If you change
methods, you must begin a new two-year period.
 (2) Value is the volume-weighted average of the gross proceeds
accruing to the seller under your or your affiliate's arm's-length
contracts for the purchase or sale of production from the field or area
during the production month.
 (i) The total volume purchased or sold under those contracts must
exceed 50 percent of your and your affiliate's production from both
Federal and non-Federal leases in the same field or area during that
month.
 (ii) Before calculating the volume-weighted average, you must
normalize the quality of the oil in your or your affiliate's arm's-
length purchases or sales to the same gravity as that of the oil
produced from the lease.
 (3) Value is the NYMEX price (without the roll), adjusted for
applicable location and quality differentials and transportation costs
under Sec. 1206.113.
 (4) If you demonstrate to ONRR's satisfaction that paragraphs
(b)(2) through (3) of this section result in an unreasonable value for
your production as a result of circumstances regarding that production,
ONRR's Director may establish an alternative valuation method.
 (c) Production from leases not located in California, Alaska, or
the Rocky Mountain Region. (1) Value is the NYMEX price, plus the roll,
adjusted for applicable location and quality differentials and
transportation costs under Sec. 1206.113.
[[Page 62079]]
 (2) If ONRR's Director determines that the use of the roll no
longer reflects prevailing industry practice in crude oil sales
contracts or that the most common formula that industry uses to
calculate the roll changes, ONRR may terminate or modify the use of the
roll under paragraph (c)(1) of this section at the end of each two-year
period as of January 1, 2017, through a notice published in the Federal
Register not later than 60 days before the end of the two-year period.
ONRR will explain the rationale for terminating or modifying the use of
the roll in this notice.
 (d) Unreasonable value. If ONRR determines that the NYMEX price or
ANS spot price does not represent a reasonable royalty value in any
particular case, ONRR may establish a 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 ONRR 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:
 (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 ONRR establishes a value representing market value at the
refinery, you may not take an allowance against that value under Sec.
1206.113(b) unless it is included in ONRR's approval.
0
5. Revise Sec. 1206.104 to read as follows:
Sec. 1206.104 How will ONRR determine if my royalty payments are
correct?
 (a)(1) ONRR may monitor, review, and audit the royalties that you
report, and, if ONRR determines that your reported value is
inconsistent with the requirements of this subpart, ONRR may establish
a reasonable royalty value based on other relevant matters.
 (2) If ONRR directs you to use a different royalty value, you must
either pay any additional royalties due, plus late payment interest
calculated under Sec. Sec. 1218.54 and 1218.102 of this chapter, or
report a credit for--or request a refund of--any overpaid royalties.
 (b) ONRR may examine whether your or your affiliate's contract
reflects the total consideration transferred for Federal oil, either
directly or indirectly, from the buyer to you or your affiliate. If
ONRR determines that additional consideration beyond that reflected in
the contract was transferred, or that any portion of the consideration
was not included in gross proceeds reported, ONRR may establish a
reasonable royalty value based on other relevant matters.
 (c) ONRR may establish a reasonable royalty value based on other
relevant matters if ONRR determines that the gross proceeds accruing to
you or your affiliate under a contract do not reflect reasonable
consideration because:
 (1) There is misconduct by or between the contracting parties;
 (2) You have breached your duty to market the oil for the mutual
benefit of yourself and the lessor; or
 (3) ONRR cannot determine if you properly valued your oil under
Sec. 1206.101 or Sec. 1206.102 for any reason including--but not
limited to--your or your affiliate's failure to provide documents that
ONRR requests under 30 CFR part 1212, subpart B.
 (d) You have the burden of demonstrating that your or your
affiliate's contract is arm's-length.
 (e) ONRR may require you to certify that the provisions in your or
your affiliate's contract include all of the consideration that the
buyer paid to you or your affiliate, either directly or indirectly, for
the oil.
 (f)(1) Absent contract revision or amendment, if you or your
affiliate fail(s) to take proper or timely action to receive prices or
benefits to which you or your affiliate are entitled, you must pay
royalty based upon that obtainable price or benefit.
 (2) If you or your affiliate apply in a timely manner for a price
increase or benefit allowed under your or your affiliate's contract,
but the purchaser refuses and you or your affiliate take reasonable
documented measures to force purchaser compliance, you will not owe
additional royalties unless or until you or your affiliate receive
additional monies or consideration resulting from the price increase.
You may not construe this paragraph to permit you to avoid your royalty
payment obligation in situations where a purchaser fails to pay, in
whole or in part or in a timely manner, for a quantity of oil.
 (g)(1) You or your affiliate must put all contracts, contract
revisions, or amendments in writing.
 (2) If you or your affiliate fail(s) to comply with paragraph
(g)(1) of this section, ONRR may establish a reasonable royalty value
based on other relevant matters.
 (3) This provision applies notwithstanding any other provisions in
this title 30 to the contrary.
0
6. Remove and reserve Sec. 1206.105.
Sec. 1206.105 [Reserved]
0
7. Revise Sec. 1206.108 to read as follows:
Sec. 1206.108 How do I request a valuation determination?
 (a) You may request a valuation determination from ONRR regarding
any oil produced. Your request must comply with all of the following:
 (1) Be in writing.
 (2) Identify, specifically, all leases involved, all interest
owners of those leases, the designee(s), and the operator(s) for those
leases.
 (3) Completely explain all relevant facts; you must inform ONRR of
any changes to relevant facts that occur before we respond to your
request.
 (4) Include copies of all relevant documents.
 (5) Provide your analysis of the issue(s).
 (6) Suggest your proposed valuation method.
 (b) In response to your request, ONRR may:
 (1) Request that the Assistant Secretary for Policy, Management and
Budget issue a valuation determination;
 (2) Decide that ONRR will issue guidance; or
 (3) Inform you in writing that ONRR will not provide a
determination or guidance. Situations in which ONRR typically will not
provide any determination or guidance include, but are not limited to,
the following:
 (i) Requests for guidance on hypothetical situations.
 (ii) Matters that are the subject of pending litigation or
administrative appeals.
 (c)(1) A valuation determination that the Assistant Secretary for
Policy, Management and Budget signs is binding on both you and ONRR
until the Assistant Secretary modifies or rescinds it.
 (2) After the Assistant Secretary for Policy, Management and Budget
issues
[[Page 62080]]
a valuation determination, you must make any adjustments to royalty
payments that follow from the determination and, if you owe additional
royalties, you must pay the additional royalties due, plus late payment
interest calculated under Sec. Sec. 1218.54 and 1218.102 of this
chapter.
 (3) A valuation determination that the Assistant Secretary for
Policy, Management and Budget signs is the final action of the
Department and is subject to judicial review under 5 U.S.C. 701-706.
 (d) Guidance that ONRR issues is not binding on ONRR, delegated
States, or you with respect to the specific situation addressed in the
guidance.
 (1) Guidance and ONRR's decision whether or not to issue guidance
or request an Assistant Secretary for Policy, Management and Budget
determination, or neither, under paragraph (b) of this section, are not
appealable decisions or orders under 30 CFR part 1290.
 (2) If you receive an order requiring you to pay royalty on the
same basis as the guidance, you may appeal that order under 30 CFR part
1290.
 (e) ONRR or the Assistant Secretary for Policy, Management and
Budget may use any of the applicable valuation criteria in this subpart
to provide guidance or to make a determination.
 (f) A change in an applicable statute or regulation on which ONRR
or the Assistant Secretary for Policy, Management and Budget based any
determination or guidance takes precedence over the determination or
guidance, regardless of whether ONRR or the Assistant Secretary
modifies or rescinds the determination or guidance.
 (g) ONRR or the Assistant Secretary for Policy, Management and
Budget generally will not retroactively modify or rescind a valuation
determination issued under paragraph (d) of this section, unless:
 (1) There was a misstatement or omission of material facts; or
 (2) The facts subsequently developed are materially different from
the facts on which the guidance was based.
 (h) ONRR may make requests and replies under this section available
to the public, subject to the confidentiality requirements under Sec.
1206.109.
0
8. Revise Sec. 1206.110 to read as follows:
Sec. 1206.110 What general transportation allowance requirements
apply to me?
 (a) ONRR will allow a deduction for the reasonable, actual costs to
transport oil from the lease to the point off of the lease under Sec.
1206.110, 1206.111, or 1206.112, as applicable. You may not deduct
transportation costs that you incur to move a particular volume of
production to reduce royalties that you owe on production for which you
did not incur those costs. This paragraph applies when:
 (1)(i) The movement to the sales point is not gathering except
 (ii) For oil produced on the OCS in waters deeper than 200 meters,
the movement of oil from the wellhead to the first platform is
transportation for which a transportation allowance may be claimed; and
 (iii) On a case-by-case basis, you may apply to ONRR to have your
actual, reasonable and necessary costs of the movement of oil produced
on the OCS in waters shallower than 200 meters from the wellhead to the
first platform to be treated as transportation for which a
transportation allowance may be claimed.
 (2) You value oil under Sec. 1206.101 based on a sale at a point
off of the lease, unit, or communitized area where the oil is produced;
or
 (3) You do not value your oil under Sec. 1206.102(a)(3) or (b)(3).
 (b) You must calculate the deduction for transportation costs based
on your or your affiliate's cost of transporting each product through
each individual transportation system. If your or your affiliate's
transportation contract includes more than one liquid product, you must
allocate costs consistently and equitably to each of the liquid
products that are transported. Your allocation must use the same
proportion as the ratio of the volume of each liquid product (excluding
waste products with no value) to the volume of all liquid products
(excluding waste products with no value).
 (1) You may not take an allowance for transporting lease production
that is not royalty-bearing.
 (2) You may propose to ONRR a prospective cost allocation method
based on the values of the liquid products transported. ONRR will
approve the method if it is consistent with the purposes of the
regulations in this subpart.
 (3) You may use your proposed procedure to calculate a
transportation allowance beginning with the production month following
the month when ONRR received your proposed procedure until ONRR accepts
or rejects your cost allocation. If ONRR rejects your cost allocation,
you must amend your Form ONRR-2014 for the months that you used the
rejected method and pay any additional royalty due, plus late payment
interest.
 (c)(1) Where you or your affiliate transport(s) both gaseous and
liquid products through the same transportation system, you must
propose a cost allocation procedure to ONRR.
 (2) You may use your proposed procedure to calculate a
transportation allowance until ONRR accepts or rejects your cost
allocation. If ONRR rejects your cost allocation, you must amend your
Form ONRR-2014 for the months when you used the rejected method and pay
any additional royalty and interest due.
 (3) You must submit your initial proposal, including all available
data, within three months after you first claim the allocated
deductions on Form ONRR-2014.
 (d)(1) Your transportation allowance may not exceed 50 percent of
the value of the oil, as determined under Sec. 1206.101, except as
provided in paragraph (d)(2) of this section.
 (2) You may ask ONRR to approve a transportation allowance in
excess of the limitation in paragraph (d)(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.
 (e) You must express transportation allowances for oil as a dollar-
value equivalent. If your or your affiliate's payments for
transportation under a contract are not on a dollar-per-unit basis, you
must convert whatever consideration you or your affiliate are paid to a
dollar-value equivalent.
 (f) ONRR may direct you to modify your transportation allowance if:
 (1) There is misconduct by or between the contracting parties;
 (2) ONRR determines that the consideration that you or your
affiliate paid under an arm's-length transportation contract does not
reflect the reasonable cost of the transportation because you breached
your duty to market the oil for the mutual benefit of yourself and the
lessor by transporting your oil at a cost that is unreasonably high; or
 (3) ONRR cannot determine if you properly calculated a
transportation allowance under Sec. 1206.111 or 1206.112 for any
reason, including, but not limited to, your or your affiliate's failure
to provide documents that ONRR requests under 30 CFR part 1212, subpart
B.
[[Page 62081]]
 (g) You do not need ONRR's approval before reporting a
transportation allowance.
0
9. Revise Sec. 1206.111 to read as follows:
Sec. 1206.111 How do I determine a transportation allowance if I
have an arm's-length transportation contract?
 (a)(1) If you or your affiliate incur transportation costs under an
arm's-length transportation contract, you may claim a transportation
allowance for the reasonable, actual costs incurred, as stated in
paragraph (b) of this section, except as provided in Sec. 1206.110(f)
and subject to the limitation in Sec. 1206.110(d).
 (2) You must be able to demonstrate that your or your affiliate's
contract is at arm's length.
 (3) You do not need ONRR's approval before reporting a
transportation allowance for costs incurred under an arm's-length
transportation contract.
 (b) Subject to the requirements of paragraph (c) of this section,
you may include, but are not limited to, the following costs to
determine your transportation allowance under paragraph (a) of this
section; you may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section including, but
not limited to:
 (1) The amount that you pay under your arm's-length transportation
contract or tariff.
 (2) Fees paid (either in volume or in value) for actual or
theoretical line losses.
 (3) Fees paid for administration of a quality bank.
 (4) Fees paid to a terminal operator for loading and unloading of
crude oil into or from a vessel, vehicle, pipeline, or other
conveyance.
 (5) Fees paid for short-term storage (30 days or less) incidental
to transportation as a transporter requires.
 (6) Fees paid to pump oil to another carrier's system or vehicles
as required under a tariff.
 (7) Transfer fees paid to a hub operator associated with physical
movement of crude oil through the hub when you do not sell the oil at
the hub. These fees do not include title transfer fees.
 (8) Payments for a volumetric deduction to cover shrinkage when
high-gravity petroleum (generally in excess of 51 degrees API) is mixed
with lower gravity crude oil for transportation.
 (9) Costs of securing a letter of credit, or other surety, that the
pipeline requires you, as a shipper, to maintain.
 (10) Hurricane surcharges that you or your affiliate actually
pay(s).
 (11) The cost of carrying on your books as inventory a volume of
oil that the pipeline operator requires you, as a shipper, to maintain
and that you do maintain in the line as line fill. You must calculate
this cost as follows:
 (i) First, multiply the volume that the pipeline requires you to
maintain--and that you do maintain--in the pipeline by the value of
that volume for the current month calculated under Sec. 1206.101 or
1206.102, as applicable.
 (ii) Second, multiply the value calculated under paragraph
(b)(11)(i) of this section by the monthly rate of return, calculated by
dividing the rate of return specified in Sec. 1206.112(i)(3) by 12.
 (c) You may not include any of the following costs to determine
your transportation allowance under paragraph (a) of this section:
 (1) Fees paid for long-term storage (more than 30 days).
 (2) Administrative, handling, and accounting fees associated with
terminalling.
 (3) Title and terminal transfer fees.
 (4) Fees paid to track and match receipts and deliveries at a
market center or to avoid paying title transfer fees.
 (5) Fees paid to brokers.
 (6) Fees paid to a scheduling service provider.
 (7) Internal costs, including salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to
schedule, nominate, and account for sale or movement of production.
 (8) Gauging fees.
 (d) (1) If you have no written contract for the arm's-length
transportation of oil, you must propose to ONRR a method to determine
the allowance using the procedures in Sec. 1206.108(a).
 (2) You may use that method to determine your allowance until ONRR
issues its determination.
0
10. Revise Sec. 1206.117 to read as follows:
Sec. 1206.117 What interest and penalties apply if I improperly
report a transportation allowance?
 (a) If you deduct a transportation allowance on Form ONRR-2014 that
exceeds 50 percent of the value of the oil transported without
obtaining ONRR's prior approval under Sec. 1206.110(d)(2), you must
pay additional royalties due, plus late payment interest calculated
under Sec. Sec. 1218.54 and 1218.102 of this chapter, on the excess
allowance amount taken from the date when that amount is taken to the
date when you file 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 late payment 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 improperly net a transportation allowance against the
oil instead of reporting the allowance as a separate entry on Form
ONRR-2014, ONRR may assess a civil penalty under 30 CFR part 1241.
Subpart D--Federal Gas
0
11. Revise Sec. 1206.141 to read as follows:
Sec. 1206.141 How do I calculate royalty value for unprocessed gas
that I or my affiliate sell(s) under an arm's-length or non-arm's-
length contract?
 (a) This section applies to unprocessed gas. Unprocessed gas is:
 (1) Gas that is not processed;
 (2) Any gas that you are not required to value under Sec.
1206.142; or
 (3) Any gas that you sell prior to processing based on a price per
MMBtu or Mcf when the price is not based on the residue gas and gas
plant products.
 (b) The value of gas under this section for royalty purposes is the
gross proceeds accruing to you or your affiliate under the first arm's-
length contract less a transportation allowance determined under Sec.
1206.152. This value does not apply if you exercise the option in
paragraph (c) of this section. Unless you elect to value your gas under
paragraph (c) of this section, you must use this paragraph (b) to value
gas when:
 (1) You sell under an arm's-length contract;
 (2) You sell or transfer unprocessed gas to your affiliate or
another person under a non-arm's-length contract and that affiliate or
person, or an affiliate of either of them, then sells the gas under an
arm's-length contract;
 (3) You, your affiliate, or another person sell(s) unprocessed gas
produced from a lease under multiple arm's-length contracts, and that
gas is valued under this paragraph. The value of the gas is the volume-
weighted average of the values, established under this paragraph, for
each contract for the sale of gas produced from that lease; or
 (4) You or your affiliate sell(s) under a pipeline cash-out
program. In that case, for over-delivered volumes within the tolerance
under a pipeline cash-out program, the value is the price that the
pipeline must pay you or your affiliate under the transportation
contract. You must use the same value for volumes that exceed the over-
delivery tolerances, even if those volumes are subject to a
[[Page 62082]]
lower price under the transportation contract.
 (c) Alternatively, you may elect to value your unprocessed gas
under this paragraph (c), which allows you to use an index-based
valuation method to calculate royalty value. You may not change your
election more often than once every two years.
 (1)(i) If you can only transport gas to one index pricing point
published in an ONRR-approved publication, available at www.onrr.gov,
your value, for royalty purposes, is the published average bidweek
price to which your gas may flow for that respective production month.
 (ii) If you can transport gas to more than one index pricing point
published in an ONRR-approved publication available at www.onrr.gov,
your value, for royalty purposes, is the highest of the published
average bidweek prices to which your gas may flow for that respective
production month, whether or not there are constraints for that
production month.
 (iii) If there are sequential index pricing points on a pipeline,
you must use the first index pricing point at or after your gas enters
the pipeline.
 (iv) You may adjust the number calculated under paragraphs
(c)(1)(i) and (ii) of this section by reducing the value by 10 percent,
but not less than 10 cents per MMBtu nor more than 40 cents per MMBtu
for sales from the OCS Gulf of Mexico and by 15 percent, but not less
than 10 cents per MMBtu nor more than 50 cents per MMBtu, for sales
from all other areas.
 (v) After you select an ONRR-approved publication available at
www.onrr.gov, you may not select a different publication more often
than once every two years.
 (vi) ONRR may exclude an individual index pricing point found in an
ONRR-approved publication if ONRR determines that the index pricing
point does not accurately reflect the values of production. ONRR will
publish criteria for index pricing points available at www.onrr.gov.
 (2) You may not take any other deductions from the value calculated
under this paragraph (c).
 (d) If some of your gas is used, lost, unaccounted for, or retained
as a fee under the terms of a sales or service agreement, that gas will
be valued for royalty purposes using the same royalty valuation method
for valuing the rest of the gas that you do sell.
 (e) If you have no written contract for the sale of gas or no sale
of gas subject to this section and:
 (1) There is an index pricing point for the gas, then you must
value your gas under paragraph (c) of this section; or
 (2) There is not an index pricing point for the gas, then:
 (i) You must propose to ONRR a method to determine the value using
the procedures in Sec. 1206.148(a).
 (ii) You may use that method to determine value, for royalty
purposes, until ONRR issues its decision.
 (iii) After ONRR issues its determination, you must make the
adjustments under Sec. 1206.143(a)(2).
 (f) Under no circumstances may your gas be valued for royalty
purposes at or less than zero.
 (g) If you elect to value your gas under paragraph (c) of this
section, ONRR reserves the right to collect actual transaction data in
the future to assess the validity of the index-based valuation option.
0
12. Revise Sec. 1206.142 to read as follows:
Sec. 1206.142 How do I calculate royalty value for processed gas that
I or my affiliate sell(s) under an arm's-length or non-arm's-length
contract?
 (a) This section applies to the valuation of processed gas,
including but not limited to:
 (1) Gas that you or your affiliate do not sell, or otherwise
dispose of, under an arm's-length contract prior to processing.
 (2) Gas where your or your affiliate's arm's-length contract for
the sale of gas prior to processing provides for payment to be
determined on the basis of the value of any products resulting from
processing, including residue gas or natural gas liquids.
 (3) Gas that you or your affiliate process under an arm's-length
keepwhole contract.
 (4) Gas where your or your affiliate's arm's-length contract
includes a reservation of the right to process the gas, and you or your
affiliate exercise(s) that right.
 (b) The value of gas subject to this section, for royalty purposes,
is the combined value of the residue gas and all gas plant products
that you determine under this section plus the value of any condensate
recovered downstream of the point of royalty settlement without
resorting to processing that you determine under subpart C of this part
less applicable transportation and processing allowances that you
determine under this subpart, unless you exercise the option provided
in paragraph (d) of this section.
 (c) The value of residue gas or any gas plant product under this
section for royalty purposes is the gross proceeds accruing to you or
your affiliate under the first arm's-length contract. This value does
not apply if you exercise the option provided in paragraph (d) of this
section. Unless you exercise the option provided in paragraph (d) of
this section, you must use this paragraph (c) to value residue gas or
any gas plant product when:
 (1) You sell under an arm's-length contract;
 (2) You sell or transfer to your affiliate or another person under
a non-arm's-length contract, and that affiliate or person, or another
affiliate of either of them, then sells the residue gas or any gas
plant product under an arm's-length contract;
 (3) You, your affiliate, or another person sell(s), under multiple
arm's-length contracts, residue gas or any gas plant products recovered
from gas produced from a lease that you value under this paragraph. In
that case, because you sold non-arm's-length to your affiliate or
another person, the value of the residue gas or any gas plant product
is the volume-weighted average of the gross proceeds established under
this paragraph for each arm's-length contract for the sale of residue
gas or any gas plant products recovered from gas produced from that
lease; or
 (4) You or your affiliate sell(s) under a pipeline cash-out
program. In that case, for over-delivered volumes within the tolerance
under a pipeline cash-out program, the value is the price that the
pipeline must pay to you or your affiliate under the transportation
contract. You must use the same value for volumes that exceed the over-
delivery tolerances, even if those volumes are subject to a lower price
under the transportation contract.
 (d) Alternatively, you may elect to value your residue gas and NGLs
under this paragraph (d). You may not change your election more often
than once every two years.
 (1)(i) If you can only transport residue gas to one index pricing
point published in an ONRR-approved publication available at
www.onrr.gov, your value, for royalty purposes, is the published
average bidweek price to which your gas may flow for that respective
production month.
 (ii) If you can transport residue gas to more than one index
pricing point published in an ONRR-approved publication available at
www.onrr.gov, your value, for royalty purposes, is the highest of the
published average bidweek prices to which your gas may flow for that
respective production month, whether or not there are constraints for
that production month.
[[Page 62083]]
 (iii) If there are sequential index pricing points on a pipeline,
you must use the first index pricing point at or after your residue gas
enters the pipeline.
 (iv) You may adjust the number calculated under paragraphs
(d)(1)(i) and (ii) of this section by reducing the value by 10 percent,
but not less than 10 cents per MMBtu nor more than 40 cents per MMBtu
for sales from the OCS Gulf of Mexico and by 15 percent, but not less
than 10 cents per MMBtu nor more than 50 cents per MMBtu for sales from
all other areas.
 (v) After you select an ONRR-approved publication available at
www.onrr.gov, you may not select a different publication more often
than once every two years.
 (vi) ONRR may exclude an individual index pricing point found in an
ONRR-approved publication if ONRR determines that the index pricing
point does not accurately reflect the values of production. ONRR will
publish criteria for index pricing points on www.onrr.gov.
 (2)(i) If you sell NGLs in an area with one or more ONRR-approved
commercial price bulletins available at www.onrr.gov, you must choose
one bulletin, and your value, for royalty purposes, is the monthly
average price for that bulletin for the production month.
 (ii) You must reduce the number calculated under paragraph
(d)(2)(i) of this section by the amounts that ONRR posts at
www.onrr.gov for the geographic location of your lease. The method that
ONRR will use to calculate the amounts is set forth in the preamble to
this regulation. This method is binding on you and ONRR. ONRR will
update the amounts periodically using this method.
 (iii) After you select an ONRR-approved commercial price bulletin
available at www.onrr.gov, you must not select a different commercial
price bulletin more often than once every two years.
 (3) You may not take any other deductions from the value calculated
under this paragraph (d).
 (4) ONRR will post changes to any of the rates in this paragraph
(d) on its website.
 (e) If some of your gas or gas plant products are used, lost,
unaccounted for, or retained as a fee under the terms of a sales or
service agreement, that gas will be valued for royalty purposes using
the same royalty valuation method for valuing the rest of the gas or
gas plant products that you do sell.
 (f) If you have no written contract for the sale of gas or no sale
of gas subject to this section and:
 (1) There is an index pricing point or commercial price bulletin
for the gas, then you must value your gas under paragraph (d) of this
section.
 (2) There is not an index pricing point or commercial price
bulletin for the gas, then:
 (i) You must propose to ONRR a method to determine the value using
the procedures in Sec. 1206.148(a).
 (ii) You may use that method to determine value, for royalty
purposes, until ONRR issues our decision.
 (iii) After ONRR issues our determination, you must make the
adjustments under Sec. 1206.143(a)(2).
 (g) Under no circumstances may your gas be valued for royalty
purposes at or less than zero.
 (h) If you elect to value your gas under paragraph (d) of this
section, ONRR reserves the right to collect actual transaction data in
the future to assess the validity of the index-based valuation option.
0
13. Revise Sec. 1206.143 to read as follows:
Sec. 1206.143 How will ONRR determine if my royalty payments are
correct?
 (a)(1) ONRR may monitor, review, and audit the royalties that you
report. If ONRR determines that your reported value is inconsistent
with the requirements of this subpart, ONRR will direct you to use a
different measure of royalty value.
 (2) If ONRR directs you to use a different royalty value, you must
either pay any additional royalties due, plus late payment interest
calculated under Sec. Sec. 1218.54 and 1218.102 of this chapter, or
report a credit for, or request a refund of, any overpaid royalties.
 (b) ONRR may examine whether your or your affiliate's contract
reflects the total consideration transferred for Federal gas, either
directly or indirectly, from the buyer to you or your affiliate. If
ONRR determines that additional consideration beyond that reflected in
the contract was transferred, or that any portion of the consideration
was not included in gross proceeds reported, ONRR may establish a
reasonable royalty value based on other relevant matters.
 (c) ONRR may direct you to use a different measure of royalty value
if ONRR determines that the gross proceeds accruing to you or your
affiliate under a contract do not reflect reasonable consideration
because:
 (1) There is misconduct by or between the contracting parties;
 (2) You have breached your duty to market the gas, residue gas, or
gas plant products for the mutual benefit of yourself and the lessor;
or
 (3) ONRR cannot determine if you properly valued your gas, residue
gas, or gas plant products under Sec. 1206.141 or Sec. 1206.142 for
any reason, including, but not limited to, your or your affiliate's
failure to provide documents that ONRR requests under 30 CFR part 1212,
subpart B.
 (d) You have the burden of demonstrating that your or your
affiliate's contract is arm's-length.
 (e) ONRR may require you to certify that the provisions in your or
your affiliate's contract include(s) all of the consideration that the
buyer paid to you or your affiliate, either directly or indirectly, for
the gas, residue gas, or gas plant products.
 (f)(1) Absent contract revision or amendment, if you or your
affiliate fail(s) to take proper or timely action to receive prices or
benefits to which you or your affiliate are entitled, you must pay
royalty based upon that obtainable price or benefit.
 (2) If you or your affiliate make timely application for a price
increase or benefit allowed under your or your affiliate's contract,
but the purchaser refuses, and you or your affiliate take reasonable,
documented measures to force purchaser compliance, you will not owe
additional royalties unless or until you or your affiliate receive
additional monies or consideration resulting from the price increase.
You may not construe this paragraph to permit you to avoid your royalty
payment obligation in situations where a purchaser fails to pay, in
whole or in part, or in a timely manner, for a quantity of gas, residue
gas, or gas plant products.
 (g)(1) You or your affiliate must make all contracts, contract
revisions, or amendments in writing.
 (2) If you or your affiliate fail(s) to comply with paragraph
(g)(1) of this section, ONRR may direct you to use a different measure
of royalty value.
 (3) This provision applies notwithstanding any other provisions in
this Title 30 to the contrary.
Sec. 1206.144 [Reserved]
0
14. Remove and reserve Sec. 1206.144.
0
15. Revise Sec. 1206.148 to read as follows:
Sec. 1206.148 How do I request a valuation determination?
 (a) You may request a valuation determination from ONRR regarding
any gas produced. Your request must comply with all of the following:
 (1) Be in writing.
 (2) Identify specifically all leases involved, all interest owners
of those leases, the designee(s), and the operator(s) for those leases.
[[Page 62084]]
 (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).
 (6) Suggest your proposed valuation method.
 (b) In response to your request, ONRR may:
 (1) Request that the Assistant Secretary for Policy, Management and
Budget issue a determination;
 (2) Decide that ONRR will issue guidance; or
 (3) Inform you in writing that ONRR will not provide a
determination or guidance. Situations in which ONRR typically will not
provide any determination or guidance include, but are not limited to:
 (i) Requests for guidance on hypothetical situations; or
 (ii) Matters that are the subject of pending litigation or
administrative appeals.
 (c)(1) A determination that the Assistant Secretary for Policy,
Management and Budget signs is binding on both you and ONRR until the
Assistant Secretary modifies or rescinds it.
 (2) After the Assistant Secretary for Policy, Management and Budget
issues a determination, you must make any adjustments to royalty
payments that follow from the determination, and, if you owe additional
royalties, you must pay the additional royalties due, plus late payment
interest calculated under Sec. Sec. 1218.54 and 1218.102 of this
chapter.
 (3) A determination that the Assistant Secretary for Policy,
Management and Budget signs is the final action of the Department and
is subject to judicial review under 5 U.S.C. 701-706.
 (d) Guidance that ONRR issues is not binding on ONRR, delegated
States, or you with respect to the specific situation addressed in the
guidance.
 (1) Guidance and ONRR's decision whether or not to issue guidance
or to request an Assistant Secretary for Policy, Management and Budget
determination, or neither, under paragraph (b) of this section, are not
appealable decisions or orders under 30 CFR part 1290.
 (2) If you receive an order requiring you to pay royalty on the
same basis as the guidance, you may appeal that order under 30 CFR part
1290.
 (e) ONRR or the Assistant Secretary for Policy, Management and
Budget may use any of the applicable criteria in this subpart to
provide guidance or to make a determination.
 (f) A change in an applicable statute or regulation on which ONRR
based any guidance, or the Assistant Secretary for Policy, Management
and Budget based any determination, takes precedence over the
determination or guidance after the effective date of the statute or
regulation, regardless of whether ONRR or the Assistant Secretary
modifies or rescinds the guidance or determination.
 (g) ONRR may make requests and replies under this section available
to the public, subject to the confidentiality requirements under Sec.
1206.149.
0
16. Revise Sec. 1260.152 to read as follows:
Sec. 1206.152 What general transportation allowance requirements
apply to me?
 (a) ONRR will allow a deduction for the reasonable, actual costs to
transport residue gas, gas plant products, or unprocessed gas from the
lease to the point off of the lease under Sec. 1206.153 or Sec.
1206.154, as applicable. You may not deduct transportation costs that
you incur when moving a particular volume of production to reduce
royalties that you owe on production for which you did not incur those
costs. This paragraph applies when:
 (1) You value unprocessed gas under Sec. 1206.141(b) or residue
gas and gas plant products under Sec. 1206.142(b) based on a sale at a
point off of the lease, unit, or communitized area where the residue
gas, gas plant products, or unprocessed gas is produced; and
 (2) The movement to the sales point is not gathering.
 (b) You must calculate the deduction for transportation costs based
on your or your affiliate's cost of transporting each product through
each individual transportation system. If your or your affiliate's
transportation contract includes more than one product in a gaseous
phase, you must allocate costs consistently and equitably to each of
the products transported. Your allocation must use the same proportion
as the ratio of the volume of each product (excluding waste products
with no value) to the volume of all products in the gaseous phase
(excluding waste products with no value).
 (1) You may not take an allowance for transporting lease production
that is not royalty-bearing.
 (2) You may propose to ONRR a prospective cost allocation method
based on the values of the products transported. ONRR will approve the
method if it is consistent with the purposes of the regulations in this
subpart.
 (3) You may use your proposed procedure to calculate a
transportation allowance beginning with the production month following
the month when ONRR received your proposed procedure until ONRR accepts
or rejects your cost allocation. If ONRR rejects your cost allocation,
you must amend your Form ONRR-2014 for the months when you used the
rejected method and pay any additional royalty due, plus late payment
interest calculated under Sec. Sec. 1218.54 and 1218.102 of this
chapter.
 (c)(1) Where you or your affiliate transport(s) both gaseous and
liquid products through the same transportation system, you must
propose a cost allocation procedure to ONRR.
 (2) You may use your proposed procedure to calculate a
transportation allowance until ONRR accepts or rejects your cost
allocation. If ONRR rejects your cost allocation, you must amend your
Form ONRR-2014 for the months when you used the rejected method and pay
any additional royalty due, plus late payment interest calculated under
Sec. Sec. 1218.54 and 1218.102 of this chapter.
 (3) You must submit your initial proposal, including all available
data, within three months after you first claim the allocated
deductions on Form ONRR-2014.
 (d) If you value unprocessed gas under Sec. 1206.141(c) or residue
gas and gas plant products under Sec. 1206.142(d), you may not take a
transportation allowance.
 (e)(1) Your transportation allowance may not exceed 50 percent of
the value of the residue gas, gas plant products, or unprocessed gas as
determined under Sec. 1206.141 or Sec. 1206.142, except as provided
in paragraph (e)(2) of this section.
 (2) You may ask ONRR to approve a transportation allowance in
excess of the limitation in paragraph (e)(1) of this section. You must
demonstrate that the transportation costs incurred in excess of the
limitations prescribed in paragraph (e)(1) of this section were
reasonable, actual, and necessary. An application for exception (using
Form ONRR-4393, Request to Exceed Regulatory Allowance Limitation) must
contain all relevant and supporting documentation necessary for ONRR to
make a determination. Under no circumstances may the value for royalty
purposes under any sales type code be reduced to zero.
 (f) You must express transportation allowances for residue gas, gas
plant products, or unprocessed gas as a dollar-value equivalent. If
your or your affiliate's payments for transportation under a contract
are not on a dollar-per-unit basis, you must convert whatever
consideration that you or your affiliate are/is paid to a dollar-value
equivalent.
[[Page 62085]]
 (g) ONRR may direct you to modify your transportation allowance if:
 (1) There is misconduct by or between the contracting parties;
 (2) ONRR determines that the consideration that you or your
affiliate paid under an arm's-length transportation contract does not
reflect the reasonable cost of the transportation because you breached
your duty to market the gas, residue gas, or gas plant products for the
mutual benefit of yourself and the lessor; or
 (3) ONRR cannot determine if you properly calculated a
transportation allowance under Sec. 1206.153 or Sec. 1206.154 for any
reason, including, but not limited to, your or your affiliate's failure
to provide documents that ONRR requests under 30 CFR part 1212, subpart
B.
 (h) You do not need ONRR's approval before reporting a
transportation allowance.
0
17. Revise Sec. 1206.153 to read as follows:
Sec. 1206.153 How do I determine a transportation allowance if I have
an arm's-length transportation contract?
 (a)(1) If you or your affiliate incur transportation costs under an
arm's-length transportation contract, you may claim a transportation
allowance for the reasonable, actual costs incurred, as more fully
explained in paragraph (b) of this section, except as provided in Sec.
1206.152(g) and subject to the limitation in Sec. 1206.152(e).
 (2) You must be able to demonstrate that your or your affiliate's
contract is arm's-length.
 (b) Subject to the requirements of paragraph (c) of this section,
you may include, but are not limited to, the following costs to
determine your transportation allowance under paragraph (a) of this
section; you may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section:
 (1) Firm demand charges paid to pipelines. You may deduct firm
demand charges or capacity reservation fees that you or your affiliate
paid to a pipeline, including charges or fees for unused firm capacity
that you or your affiliate have not sold before you report your
allowance. If you or your affiliate receive(s) a payment from any party
for release or sale of firm capacity after reporting a transportation
allowance that included the cost of that unused firm capacity, or if
you or your affiliate receive(s) a payment or credit from the pipeline
for penalty refunds, rate case refunds, or other reasons, you must
reduce the firm demand charge claimed on Form ONRR-2014 by the amount
of that payment. You must modify Form ONRR-2014 by the amount received
or credited for the affected reporting period and pay any resulting
royalty due, plus late payment interest calculated under Sec. Sec.
1218.54 and 1218.102 of this chapter.
 (2) Gas Supply Realignment (GSR) costs. The GSR costs result from a
pipeline reforming or terminating supply contracts with producers in
order to implement the restructuring requirements of FERC Orders in 18
CFR part 284.
 (3) Commodity charges. The commodity charge allows the pipeline to
recover the costs of providing service.
 (4) Wheeling costs. Hub operators charge a wheeling cost for
transporting gas from one pipeline to either the same or another
pipeline through a market center or hub. A hub is a connected manifold
of pipelines through which a series of incoming pipelines are
interconnected to a series of outgoing pipelines.
 (5) Gas Research Institute (GRI) fees. The GRI conducts research,
development, and commercialization programs on natural gas-related
topics for the benefit of the U.S. gas industry and gas customers. GRI
fees are allowable, provided that such fees are mandatory in FERC-
approved tariffs.
 (6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to
pipelines to pay for its operating expenses.
 (7) Payments (either volumetric or in value) for actual or
theoretical losses. Theoretical losses are not deductible in
transportation arrangements unless the transportation allowance is
based on arm's-length transportation rates charged under a FERC or
State regulatory-approved tariff. If you or your affiliate receive(s)
volumes or credit for line gain, you must reduce your transportation
allowance accordingly and pay any resulting royalties plus late payment
interest calculated under Sec. Sec. 1218.54 and 1218.102 of this
chapter;
 (8) Temporary storage services. This includes short-duration
storage services that market centers or hubs (commonly referred to as
``parking'' or ``banking'') offer or other temporary storage services
that pipeline transporters provide, whether actual or provided as a
matter of accounting. Temporary storage is limited to 30 days or fewer.
 (9) Supplemental costs for compression, dehydration, and treatment
of gas. ONRR allows these costs only if such services are required for
transportation and exceed the services necessary to place production
into marketable condition required under Sec. 1206.146.
 (10) Costs of surety. You may deduct the costs of securing a letter
of credit, or other surety, that the pipeline requires you or your
affiliate, as a shipper, to maintain under a transportation contract.
 (11) Hurricane surcharges. You may deduct hurricane surcharges that
you or your affiliate actually pay(s).
 (c) You may not include the following costs to determine your
transportation allowance under paragraph (a) of this section:
 (1) Fees or costs incurred for storage. This includes storing
production in a storage facility, whether on or off of the lease, for
more than 30 days.
 (2) Aggregator/marketer fees. This includes fees that you or your
affiliate pay(s) to another person (including your affiliates) to
market your gas, including purchasing and reselling the gas or finding
or maintaining a market for the gas production.
 (3) Penalties that you or your affiliate incur(s) as a shipper.
These penalties include, but are not limited to:
 (i) Over-delivery cash-out penalties. This includes the difference
between the price that the pipeline pays to you or your affiliate for
over-delivered volumes outside of the tolerances and the price that you
or your affiliate receive(s) for over-delivered volumes within the
tolerances.
 (ii) Scheduling penalties. This includes penalties that you or your
affiliate incur(s) for differences between daily volumes delivered into
the pipeline and volumes scheduled or nominated at a receipt or
delivery point.
 (iii) Imbalance penalties. This includes penalties that you or your
affiliate incur(s) (generally on a monthly basis) for differences
between volumes delivered into the pipeline and volumes scheduled or
nominated at a receipt or delivery point.
 (iv) Operational penalties. This includes fees that you or your
affiliate incur(s) for violation of the pipeline's curtailment or
operational orders issued to protect the operational integrity of the
pipeline.
 (4) Intra-hub transfer fees. These are fees that you or your
affiliate pay(s) to hub operators for administrative services (such as
title transfer tracking) necessary to account for the sale of gas
within a hub.
 (5) Fees paid to brokers. This includes fees that you or your
affiliate pay(s) to parties who arrange marketing or transportation, if
such fees are separately identified from aggregator/marketer fees.
 (6) Fees paid to scheduling service providers. This includes fees
that you or your affiliate pay(s) to parties who
[[Page 62086]]
provide scheduling services, if such fees are separately identified
from aggregator/marketer fees.
 (7) Internal costs. This includes salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to
schedule, nominate, and account for the sale or movement of production.
 (8) Other non-allowable costs. Any cost you or your affiliate
incur(s) for services that you are required to provide at no cost to
the lessor, including, but not limited to, costs to place your gas,
residue gas, or gas plant products into marketable condition disallowed
under Sec. 1206.146 and costs of boosting residue gas disallowed under
Sec. 1202.151(b) of this chapter.
 (d) If you have no written contract for the arm's-length
transportation of gas, and neither you nor your affiliate perform your
own transportation, you must propose to ONRR a method to determine the
transportation allowance using the procedures in Sec. 1206.148(a).
 (1) You may use that method to determine your allowance until ONRR
issues its determination.
 (2) [RESERVED]
0
18. Revise Sec. 1206.157 to read as follows:
Sec. 1206.157 What interest and penalties apply if I improperly
report a transportation allowance?
 (a)(1) If ONRR determines that you took an unauthorized
transportation allowance, then you must pay any additional royalties
due, plus late payment interest calculated under Sec. Sec. 1218.54 and
1218.102 of this chapter.
 (2) If you understated your transportation allowance, you may be
entitled to a credit, with interest.
 (b) If you deduct a transportation allowance on Form ONRR-2014 that
exceeds 50 percent of the value of the gas, residue gas, or gas plant
products transported without obtaining ONRR's prior approval under
Sec. 1206.152(e)(2), you must pay additional royalties due, plus late
payment interest calculated under Sec. Sec. 1218.54 and 1218.102 of
this chapter, on the excess allowance amount taken from the date when
that amount is taken to the date when you file 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 late payment interest on
the excess allowance amount taken from the date that amount is taken
until the date you pay the additional royalties owed.
 (c) If you improperly net a transportation allowance against the
sales value of the residue gas, gas plant products, or unprocessed gas
instead of reporting the allowance as a separate entry on Form ONRR-
2014, ONRR may assess a civil penalty under 30 CFR part 1241.
0
19. Revise Sec. 1206.159 to read as follows:
Sec. 1206.159 What general processing allowances requirements apply
to me?
 (a)(1) When you value any gas plant product under Sec.
1206.142(c), you may deduct from the value the reasonable, actual costs
of processing.
 (2) You do not need ONRR's approval before reporting a processing
allowance.
 (b) You must allocate processing costs among the gas plant
products. You must determine a separate processing allowance for each
gas plant product and processing plant relationship. ONRR considers
NGLs to be one product.
 (c)(1) You may not apply the processing allowance against the value
of the residue gas, except as provided in paragraph (c)(4) of this
section.
 (2) The processing allowance deduction on the basis of an
individual product may not exceed 66\2/3\ percent of the value of each
gas plant product determined under Sec. 1206.142(c), except as
provided under paragraphs (c)(3) or (4) of this section. Before you
calculate the 66\2/3\-percent limit, you must first reduce the value
for any transportation allowances related to post-processing
transportation authorized under Sec. 1206.152.
 (3) You may ask ONRR to approve a processing allowance in excess of
the limitation prescribed by paragraph (c)(2) of this section. You 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) must
contain all relevant and supporting documentation for ONRR to make a
determination. Under no circumstances may the value for royalty
purposes of any gas plant product be reduced to zero.
 (4) If you incur extraordinary costs for processing gas, you may
apply to ONRR for an allowance for those costs which must be in
addition to any other processing allowance to which the lessee is
entitled pursuant to this section. You must demonstrate that the costs
are, by reference to standard industry conditions and practice,
extraordinary, unusual, or unconventional. You are not required to
receive ONRR approval to continue an extraordinary processing
allowance. However, you must report the deduction to ONRR in a form and
manner prescribed by ONRR in order to retain the ability to deduct the
allowance.
 (d)(1) ONRR will not allow a processing cost deduction for the
costs of placing lease products in marketable condition, including
dehydration, separation, compression, or storage, even if those
functions are performed off the lease or at a processing plant.
 (2) Where gas is processed for the removal of acid gases, commonly
referred to as ``sweetening,'' ONRR will not allow processing cost
deductions for such costs unless the acid gases removed are further
processed into a gas plant product.
 (i) In such event, you are eligible for a processing allowance
determined under this subpart.
 (ii) ONRR will not grant any processing allowance for processing
lease production that is not royalty bearing.
 (e) ONRR may direct you to modify your processing allowance if:
 (1) There is misconduct by or between the contracting parties;
 (2) ONRR determines that the consideration that you or your
affiliate paid under an arm's-length processing contract does not
reflect the reasonable cost of the processing because you breached your
duty to market the gas, residue gas, or gas plant products for the
mutual benefit of yourself and the lessor; or
 (3) ONRR cannot determine if you properly calculated a processing
allowance under Sec. 1206.160 or Sec. 1206.161 for any reason,
including, but not limited to, your or your affiliate's failure to
provide documents that ONRR requests under 30 CFR part 1212, subpart B.
0
20. Revise Sec. 1206.160 to read as follows:
Sec. 1206.160 How do I determine a processing allowance if I have an
arm's-length processing contract?
 (a)(1) If you or your affiliate incur processing costs under an
arm's-length processing contract, you may claim a processing allowance
for the reasonable, actual costs incurred, as more fully explained in
paragraph (b) of this section, except as provided in Sec. 1206.159(e)
and subject to the limitation in Sec. 1206.159(c)(2).
 (2) You must be able to demonstrate that your or your affiliate's
contract is arm's-length.
 (b)(1) If your or your affiliate's arm's-length processing contract
includes more than one gas plant product, and you can determine the
processing costs for each product based on the contract, then you must
determine the processing
[[Page 62087]]
costs for each gas plant product under the contract.
 (2) If your or your affiliate's arm's-length processing contract
includes more than one gas plant product, and you cannot determine the
processing costs attributable to each product from the contract, you
must propose an allocation procedure to ONRR.
 (i) You may use your proposed allocation procedure until ONRR
issues its determination.
 (ii) You must submit all relevant data to support your proposal.
 (iii) ONRR will determine the processing allowance based upon your
proposal and any additional information that ONRR deems necessary.
 (iv) You must submit the allocation proposal within three months of
claiming the allocated deduction on Form ONRR-2014.
 (3) You may not take an allowance for the costs of processing lease
production that is not royalty-bearing.
 (4) If your or your affiliate's payments for processing under an
arm's-length contract are not based on a dollar-per-unit basis, you
must convert whatever consideration that you or your affiliate paid to
a dollar-value equivalent.
 (c) If you have no written contract for the arm's-length processing
of gas, and neither you nor your affiliate perform your own processing,
you must propose to ONRR a method to determine the processing allowance
using the procedures in Sec. 1206.148(a).
 (1) You may use that method to determine your allowance until ONRR
issues a determination.
 (2) [RESERVED]
0
21. Revise Sec. 1206.164 to read as follows:
Sec. 1206.164 What interest and penalties apply if I improperly
report a processing allowance?
 (a)(1) If ONRR determines that you took an unauthorized processing
allowance, then you must pay any additional royalties due, plus late
payment interest calculated under Sec. Sec. 1218.54 and 1218.102 of
this chapter.
 (2) If you understated your processing allowance, you may be
entitled to a credit, with interest.
 (b) If you deduct a processing allowance on Form ONRR-2014 that
exceeds 66\2/3\ percent of the value of a gas plant product without
obtaining ONRR's prior approval under Sec. 1206.159(c)(3), you must
pay additional royalties due, plus late payment interest calculated
under Sec. Sec. 1218.54 and 1218.102 of this chapter, on the excess
allowance amount taken from the date when that amount is taken to the
date when you file 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 late payment interest on the excess allowance
amount taken from the date that amount is taken until the date you pay
the additional royalties owed.
 (c) If you improperly net a processing allowance against the sales
value of a gas plant product instead of reporting the allowance as a
separate entry on Form ONRR-2014, ONRR may assess a civil penalty under
30 CFR part 1241.
Subpart F--Federal Coal
0
22. Revise Sec. 1206.252 to read as follows:
Sec. 1206.252 How do I calculate royalty value for coal that I or my
affiliate sells under an arm's-length or non-arm's-length contract?
 (a) The value of coal under this section for royalty purposes is
the gross proceeds accruing to you or your affiliate under the first
arm's-length contract, less an applicable transportation allowance
determined under Sec. Sec. 1206.260 through 1206.262 and washing
allowance under Sec. Sec. 1206.267 through 1206.269. You must use this
paragraph (a) to value coal when:
 (1) You sell under an arm's-length contract; or
 (2) You sell or transfer to your affiliate or another person under
a non-arm's-length contract, and that affiliate or person, or another
affiliate of either of them, then sells the coal under an arm's-length
contract.
 (b) If you have no contract for the sale of coal subject to this
section because you or your affiliate used the coal in a power plant
that you or your affiliate own(s) for the generation and sale of
electricity:
 (i) You must propose to ONRR a method to determine the value using
the procedures in Sec. 1206.258(a).
 (ii) You must use that method to determine value, for royalty
purposes, until ONRR issues a determination.
 (iii) After ONRR issues a determination, you must make the
adjustments, if any, under Sec. 1206.253(a)(2).
 (c) If you are entitled to take a washing allowance and
transportation allowance for royalty purposes under this section, under
no circumstances may the washing allowance plus the transportation
allowance reduce the royalty value of the coal to zero.
0
23. Revise Sec. 1206.253 to read as follows:
Sec. 1206.253 How will ONRR determine if my royalty payments are
correct?
 (a)(1) ONRR may monitor, review, and audit the royalties that you
report, and, if ONRR determines that your reported value is
inconsistent with the requirements of this subpart, ONRR may establish
a reasonable royalty value based on other relevant matters.
 (2) If ONRR directs you to use a different royalty value, you must
either pay any underpaid royalties due, plus late payment interest
calculated under Sec. 1218.202 of this chapter, or report a credit
for--or request a refund of--any overpaid royalties.
 (b) ONRR may examine whether your or your affiliate's contract
reflects the total consideration transferred for Federal coal, either
directly or indirectly, from the buyer to you or your affiliate. If
ONRR determines that additional consideration beyond that reflected in
the contract was transferred, or that any portion of the consideration
was not included in gross proceeds reported, ONRR may establish a
reasonable royalty value based on other relevant matters.
 (c) ONRR may establish a reasonable royalty value based on other
relevant matters if ONRR determines that the gross proceeds accruing to
you or your affiliate under a contract do not reflect reasonable
consideration because:
 (1) There is misconduct by or between the contracting parties;
 (2) You breached your duty to market the coal for the mutual
benefit of yourself and the lessor; or
 (3) ONRR cannot determine if you properly valued your coal under
Sec. 1206.252 for any reason, including, but not limited to, your or
your affiliate's failure to provide documents to ONRR under 30 CFR part
1212, subpart E.
 (d) You have the burden of demonstrating that your or your
affiliate's contract is arm's-length.
 (e) ONRR may require you to certify that the provisions in your or
your affiliate's contract include(s) all of the consideration that the
buyer paid to you or your affiliate, either directly or indirectly, for
the coal.
 (f)(1) Absent any contract revisions or amendments, if you or your
affiliate fail(s) to take proper or timely action to receive prices or
benefits to which you or your affiliate are entitled, you must pay
royalty based upon that obtainable price or benefit.
 (2) If you or your affiliate apply in a timely manner for a price
increase or benefit allowed under your or your affiliate's contract,
but the purchaser refuses, and you or your affiliate take reasonable,
documented measures to force purchaser compliance, you will not owe
additional royalties unless or until you or your affiliate receive
additional monies or consideration
[[Page 62088]]
resulting from the price increase. You may not construe this paragraph
to permit you to avoid your royalty payment obligation in situations
where a purchaser fails to pay in whole or in part, or in a timely
manner, for a quantity of coal.
 (g)(1) You or your affiliate must make all contracts, contract
revisions, or amendments in writing.
 (2) If you or your affiliate fail(s) to comply with paragraph
(g)(1) of this section, ONRR may establish a reasonable royalty value
based on other relevant matters.
 (3) This provision applies notwithstanding any other provisions in
this title 30 to the contrary.
Sec. 1206.254 [Reserved]
0
24. Remove and reserve Sec. 1206.254.
0
25. Revise Sec. 1206.258 to read as follows:
Sec. 1206.258 How do I request a valuation determination?
 (a) You may request a valuation determination from ONRR regarding
any coal produced. Your request must comply with all of the following:
 (1) Be in writing.
 (2) Identify specifically all leases involved, all interest owners
of those leases, and the operator(s) for those leases.
 (3) Completely explain all relevant facts. You must inform ONRR of
any changes to relevant facts that occur before we respond to your
request.
 (4) Include copies of all relevant documents.
 (5) Provide your analysis of the issue(s).
 (6) Suggest a proposed valuation method.
 (b) In response to your request, ONRR may:
 (1) Request that the Assistant Secretary for Policy, Management and
Budget issue a determination;
 (2) Decide that ONRR will issue guidance; or
 (3) Inform you in writing that ONRR will not provide a
determination or guidance. Situations in which ONRR typically will not
provide any determination or guidance include, but are not limited to:
 (i) Requests for guidance on hypothetical situations; or
 (ii) Matters that are the subject of pending litigation or
administrative appeals.
 (c)(1) A determination that the Assistant Secretary for Policy,
Management and Budget signs is binding on both you and ONRR until the
Assistant Secretary modifies or rescinds it.
 (2) After the Assistant Secretary for Policy, Management and Budget
issues a determination, you must make any adjustments in royalty
payments that follow from the determination and, if you owe additional
royalties, you must pay any additional royalties due, plus late payment
interest calculated under Sec. 1218.202 of this chapter.
 (3) A determination that the Assistant Secretary for Policy,
Management and Budget signs is the final action of the Department and
is subject to judicial review under 5 U.S.C. 701-706.
 (d) Guidance that ONRR issues is not binding on ONRR, delegated
States, or you with respect to the specific situation addressed in the
guidance.
 (1) Guidance and ONRR's decision whether or not to issue guidance
or to request an Assistant Secretary for Policy, Management and Budget
determination, or neither, under paragraph (b) of this section, are not
appealable decisions or orders under 30 CFR part 1290.
 (2) If you receive an order requiring you to pay royalty on the
same basis as the guidance, you may appeal that order under 30 CFR part
1290.
 (e) ONRR or the Assistant Secretary for Policy, Management and
Budget may use any of the applicable criteria in this subpart to
provide guidance or to make a determination.
 (f) A change in an applicable statute or regulation on which ONRR
based any guidance, or the Assistant Secretary for Policy, Management
and Budget based any determination, takes precedence over the
determination or guidance after the effective date of the statute or
regulation, regardless of whether ONRR or the Assistant Secretary
modifies or rescinds the guidance or determination.
 (g) ONRR or the Assistant Secretary for Policy, Management and
Budget generally will not retroactively modify or rescinds a valuation
determination issued under paragraph (d) of this section, unless:
 (1) There was a misstatement or omission of material facts; or
 (2) The facts subsequently developed are materially different from
the facts on which the guidance was based.
 (h) ONRR may make requests and replies under this section available
to the public, subject to the confidentiality requirements under Sec.
1206.259.
0
26. Revise Sec. 1206.260 to read as follows:
Sec. 1206.260 What general transportation allowance requirements
apply to me?
 (a)(1) ONRR will allow a deduction for the reasonable, actual costs
to transport coal from the lease to the point off of the lease or mine
as determined under Sec. 1206.261 or 1206.262, as applicable.
 (2) You do not need ONRR's approval before reporting a
transportation allowance for costs incurred.
 (b) You may take a transportation allowance when:
 (1) You value coal under Sec. 1206.252;
 (2) You transport the coal from a Federal lease to a sales point,
which is remote from both the lease and mine; or
 (3) You transport the coal from a Federal lease to a wash plant
when that plant is remote from both the lease and mine and, if
applicable, from the wash plant to a remote sales point.
 (c) You may not take an allowance for:
 (1) Transporting lease production that is not royalty-bearing;
 (2) In-mine movement of your coal; or
 (3) Costs to move a particular tonnage of production for which you
did not incur those costs.
 (d) You may only claim a transportation allowance when you sell the
coal and pay royalties.
 (e) You must allocate transportation allowances to the coal
attributed to the lease from which it was extracted.
 (1) If you commingle coal produced from Federal and non-Federal
leases, you may not disproportionately allocate transportation costs to
Federal lease production. Your allocation must use the same proportion
as the ratio of the tonnage from the Federal lease production to the
tonnage from all production.
 (2) If you commingle coal produced from more than one Federal
lease, you must allocate transportation costs to each Federal lease, as
appropriate. Your allocation must use the same proportion as the ratio
of the tonnage of each Federal lease production to the tonnage of all
production.
 (3) For washed coal, you must allocate the total transportation
allowance only to washed products.
 (4) For unwashed coal, you may take a transportation allowance for
the total coal transported.
 (5)(i) You must report your transportation costs on Form ONRR-4430
as clean coal short tons sold during the reporting period multiplied by
the sum of the per-short-ton cost of transporting the raw tonnage to
the wash plant and, if applicable, the per-short-ton cost of
transporting the clean coal tons from the wash plant to a remote sales
point.
 (ii) You must determine the cost per short ton of clean coal
transported by dividing the total applicable transportation cost by the
number of clean coal tons resulting from washing the raw coal
transported.
 (f) You must express transportation allowances for coal as a
dollar-value
[[Page 62089]]
equivalent per short ton of coal transported. If you do not base your
or your affiliate's payments for transportation under a transportation
contract on a dollar-per-unit basis, you must convert whatever
consideration that you or your affiliate paid to a dollar-value
equivalent.
 (g) ONRR may determine your transportation allowance if:
 (1) There is misconduct by or between the contracting parties;
 (2) ONRR determines that the consideration that you or your
affiliate paid under an arm's-length transportation contract does not
reflect the reasonable cost of the transportation because you breached
your duty to market the coal for the mutual benefit of yourself and the
lessor by transporting your coal at a cost that is unreasonably high;
or
 (3) ONRR cannot determine if you properly calculated a
transportation allowance under Sec. 1206.261 or Sec. 1206.262 for any
reason, including, but not limited to, your or your affiliate's failure
to provide documents that ONRR requests under 30 CFR part 1212, subpart
E.
0
27. Revise Sec. 1206.261 to read as follows:
Sec. 1206.261 How do I determine a transportation allowance if I
have an arm's-length transportation contract?
 (a) If you or your affiliate incur(s) transportation costs under an
arm's-length transportation contract, you may claim a transportation
allowance for the reasonable, actual costs incurred for transporting
the coal under that contract.
 (b) You must be able to demonstrate that your or your affiliate's
contract is at arm's-length.
 (c) If you have no written contract for the arm's-length
transportation of coal, and neither you nor your affiliate perform your
own transportation, you must propose to ONRR a method to determine the
transportation allowance using the procedures in Sec. 1206.258(a).
 (1) You must use that method to determine your allowance until ONRR
issues a determination.
 (2) [RESERVED]
0
28. Revise Sec. 1206.267 to read as follows:
Sec. 1206.267 What general washing allowance requirements apply to
me?
 (a)(1) If you determine the value of your coal under Sec.
1206.252, you may take a washing allowance for the reasonable, actual
costs to wash the coal. The allowance is a deduction when determining
coal royalty value for the costs that you incur to wash coal.
 (2) You do not need ONRR's approval before reporting a washing
allowance.
 (b) You may not:
 (1) Take an allowance for the costs of washing lease production
that is not royalty bearing.
 (2) Disproportionately allocate washing costs to Federal leases.
You must allocate washing costs to washed coal attributable to each
Federal lease by multiplying the input ratio determined under Sec.
1206.251(e)(2)(i) by the total allowable costs.
 (c)(1) You must express washing allowances for coal as a dollar-
value equivalent per short ton of coal washed.
 (2) If you do not base your or your affiliate's payments for
washing under an arm's-length contract on a dollar-per-unit basis, you
must convert whatever consideration that you or your affiliate paid to
a dollar-value equivalent.
 (d) ONRR may direct you to modify your washing allowance if:
 (1) There is misconduct by or between the contracting parties;
 (2) ONRR determines that the consideration that you or your
affiliate paid under an arm's-length washing contract does not reflect
the reasonable cost of the washing because you breached your duty to
market the coal for the mutual benefit of yourself and the lessor by
washing your coal at a cost that is unreasonably high; or
 (3) ONRR cannot determine if you properly calculated a washing
allowance under Sec. Sec. 1206.267 through 1206.269 for any reason,
including, but not limited to, your or your affiliate's failure to
provide documents that ONRR requests under 30 CFR part 1212, subpart E.
 (e) You may only claim a washing allowance when you sell the washed
coal and report and pay royalties.
0
29. Revise Sec. 1206.268 to read as follows:
Sec. 1206.268 How do I determine washing allowances if I have an
arm's-length washing contract or no written arm's-length contract?
 (a) If you or your affiliate incur(s) washing costs under an arm's-
length washing contract, you may claim a washing allowance for the
reasonable, actual costs incurred.
 (b) You must be able to demonstrate that your or your affiliate's
washing contract is arm's-length.
 (c) If you have no written contract for the arm's-length washing of
coal, and neither you nor your affiliate perform your own washing, you
must propose to ONRR a method to determine the washing allowance using
the procedures in Sec. 1206.258(a).
 (1) You must use that method to determine your allowance until ONRR
issues a determination.
 (2) [RESERVED]
Subpart J--Indian Coal
0
30. Revise Sec. 1206.452 to read as follows:
Sec. 1206.452 How do I calculate royalty value for coal that I or my
affiliate sell(s) under an arm's-length or non-arm's-length contract?
 (a) The value of coal under this section for royalty purposes is
the gross proceeds accruing to you or your affiliate under the first
arm's-length contract, less an applicable transportation allowance
determined under Sec. Sec. 1206.460 through 1206.462 and washing
allowance under Sec. Sec. 1206.467 through 1206.469. You must use this
paragraph (a) to value coal when:
 (1) You sell under an arm's-length contract; or
 (2) You sell or transfer to your affiliate or another person under
a non-arm's-length contract, and that affiliate or person, or another
affiliate of either of them, then sells the coal under an arm's-length
contract.
 (b) If you have no contract for the sale of coal subject to this
section because you or your affiliate used the coal in a power plant
that you or your affiliate own(s) for the generation and sale of
electricity:
 (i) You must propose to ONRR a method to determine the value using
the procedures in Sec. 1206.458(a).
 (ii) You must use that method to determine value, for royalty
purposes, until ONRR issues a determination.
 (iii) After ONRR issues a determination, you must make the
adjustments under Sec. 1206.453(a)(2).
 (c) If you are entitled to take a washing allowance and
transportation allowance for royalty purposes under this section, under
no circumstances may the washing allowance plus the transportation
allowance reduce the royalty value of the coal to zero.
0
31. Revise Sec. 1206.453 to read as follows:
Sec. 1206.453 How will ONRR determine if my royalty payments are
correct?
 (a)(1) ONRR may monitor, review, and audit the royalties that you
report, and, if ONRR determines that your reported value is
inconsistent with the requirements of this subpart, ONRR may establish
a reasonable royalty value based on other relevant matters.
 (2) If ONRR directs you to use a different royalty value, you must
either pay any underpaid royalties due, plus
[[Page 62090]]
late payment interest calculated under Sec. 1218.202 of this chapter,
or report a credit for--or request a refund of--any overpaid royalties.
 (b) ONRR may examine whether your or your affiliate's contract
reflects the total consideration transferred for Indian coal, either
directly or indirectly, from the buyer to you or your affiliate. If
ONRR determines that additional consideration beyond that reflected in
the contract was transferred, or that any portion of the consideration
was not included in gross proceeds reported, ONRR may establish a
reasonable royalty value based on other relevant matters.
 (c) ONRR may establish a reasonable royalty value based on other
relevant matters if ONRR determines that the gross proceeds accruing to
you or your affiliate under a contract do not reflect reasonable
consideration because:
 (1) There is misconduct by or between the contracting parties;
 (2) You breached your duty to market the coal for the mutual
benefit of yourself and the lessor; or
 (3) ONRR cannot determine if you properly valued your coal under
Sec. 1206.452 for any reason, including, but not limited to, your or
your affiliate's failure to provide documents to ONRR under 30 CFR part
1212, subpart E.
 (d) You have the burden of demonstrating that your or your
affiliate's contract is arm's-length.
 (e) ONRR may require you to certify that the provisions in your or
your affiliate's contract include(s) all of the consideration that the
buyer paid to you or your affiliate, either directly or indirectly, for
the coal.
 (f)(1) Absent any contract revisions or amendments, if you or your
affiliate fail(s) to take proper or timely action to receive prices or
benefits to which you or your affiliate are entitled, you must pay
royalty based upon that obtainable price or benefit.
 (2) If you or your affiliate apply in a timely manner for a price
increase or benefit allowed under your or your affiliate's contract,
but the purchaser refuses, and you or your affiliate take reasonable,
documented measures to force purchaser compliance, you will not owe
additional royalties unless or until you or your affiliate receive
additional monies or consideration resulting from the price increase.
You may not construe this paragraph to permit you to avoid your royalty
payment obligation in situations where a purchaser fails to pay in
whole or in part, or in a timely manner, for a quantity of coal.
 (g)(1) You or your affiliate must make all contracts, contract
revisions, or amendments in writing.
 (2) If you or your affiliate fail(s) to comply with paragraph
(g)(1) of this section, ONRR may establish a reasonable royalty value
based on other relevant matters.
 (3) This provision applies notwithstanding any other provisions in
this title 30 to the contrary.
Sec. 1206.454 [Removed and reserved]
0
32. Remove and reserve Sec. 1206.454.
0
33. Revise Sec. 1206.458 to read as follows:
Sec. 1206.458 How do I request a valuation determination?
 (a) You may request a valuation determination from ONRR regarding
any coal produced. Your request must comply with all of the:
 (1) Be in writing.
 (2) Identify specifically all leases involved, all interest owners
of those leases, and the operator(s) for those leases.
 (3) Completely explain all relevant facts. You must inform ONRR of
any changes to relevant facts that occur before we respond to your
request.
 (4) Include copies of all relevant documents.
 (5) Provide your analysis of the issue(s).
 (6) Suggest a proposed valuation method.
 (b) In response to your request, ONRR may:
 (1) Request that the Assistant Secretary for Policy, Management and
Budget issue a determination;
 (2) Decide that ONRR will issue guidance; or
 (3) Inform you in writing that ONRR will not provide a
determination or guidance. Situations in which ONRR typically will not
provide any determination or guidance include, but are not limited to:
 (i) Requests for guidance on hypothetical situations; or
 (ii) Matters that are the subject of pending litigation or
administrative appeals.
 (c)(1) A determination that the Assistant Secretary for Policy,
Management and Budget signs is binding on both you and ONRR until the
Assistant Secretary modifies or rescinds it.
 (2) After the Assistant Secretary for Policy, Management and Budget
issues a determination, you must make any adjustments in royalty
payments that follow from the determination and, if you owe additional
royalties, you must pay any additional royalties due, plus late payment
interest calculated under Sec. 1218.202 of this chapter.
 (3) A determination that the Assistant Secretary for Policy,
Management and Budget signs is the final action of the Department and
is subject to judicial review under 5 U.S.C. 701-706.
 (d) Guidance that ONRR issues is not binding on ONRR, delegated
States, or you with respect to the specific situation addressed in the
guidance.
 (1) Guidance and ONRR's decision whether or not to issue guidance
or to request an Assistant Secretary for Policy, Management and Budget
determination, or neither, under paragraph (b) of this section, are not
appealable decisions or orders under 30 CFR part 1290.
 (2) If you receive an order requiring you to pay royalty on the
same basis as the guidance, you may appeal that order under 30 CFR part
1290.
 (e) ONRR or the Assistant Secretary for Policy, Management and
Budget may use any of the applicable criteria in this subpart to
provide guidance or to make a determination.
 (f) A change in an applicable statute or regulation on which ONRR
based any guidance, or the Assistant Secretary for Policy, Management
and Budget based any determination, takes precedence over the
determination or guidance after the effective date of the statute or
regulation, regardless of whether ONRR or the Assistant Secretary
modifies or rescinds the guidance or determination.
 (g) ONRR or the Assistant Secretary for Policy, Management and
Budget generally will not retroactively modify or rescind a valuation
determination issued under paragraph (d) of this section, unless:
 (1) There was a misstatement or omission of material facts; or
 (2) The facts subsequently developed are materially different from
the facts on which the guidance was based.
 (h) ONRR may make requests and replies under this section available
to the public, subject to the confidentiality requirements under Sec.
1206.259.
0
34. Revise Sec. 1206.460 to read as follows:
Sec. 1206.460 What general transportation allowance requirements
apply to me?
 (a)(1) ONRR will allow a deduction for the reasonable, actual costs
to transport coal from the lease to the point off of the lease or mine
as determined under Sec. 1206.461 or 1206.462, as applicable.
 (2) You do not need ONRR's approval before reporting a
transportation allowance for costs incurred.
 (b) You may take a transportation allowance when:
[[Page 62091]]
 (1) You value coal under Sec. 1206.452;
 (2) You transport the coal from a Federal lease to a sales point,
which is remote from both the lease and mine; or
 (3) You transport the coal from a Federal lease to a wash plant
when that plant is remote from both the lease and mine and, if
applicable, from the wash plant to a remote sales point.
 (c) You may not take an allowance for:
 (1) Transporting lease production that is not royalty-bearing;
 (2) In-mine movement of your coal; or
 (3) Costs to move a particular tonnage of production for which you
did not incur those costs.
 (d) You may only claim a transportation allowance when you sell the
coal and pay royalties.
 (e) You must allocate transportation allowances to the coal
attributed to the lease from which it was extracted.
 (1) If you commingle coal produced from Federal and non-Federal
leases, you may not disproportionately allocate transportation costs to
Federal lease production. Your allocation must use the same proportion
as the ratio of the tonnage from the Federal lease production to the
tonnage from all production.
 (2) If you commingle coal produced from more than one Federal
lease, you must allocate transportation costs to each Federal lease, as
appropriate. Your allocation must use the same proportion as the ratio
of the tonnage of each Federal lease production to the tonnage of all
production.
 (3) For washed coal, you must allocate the total transportation
allowance only to washed products.
 (4) For unwashed coal, you may take a transportation allowance for
the total coal transported.
 (5)(i) You must report your transportation costs on Form ONRR-4430
as clean coal short tons sold during the reporting period multiplied by
the sum of the per-short-ton cost of transporting the raw tonnage to
the wash plant and, if applicable, the per-short-ton cost of
transporting the clean coal tons from the wash plant to a remote sales
point.
 (ii) You must determine the cost per short ton of clean coal
transported by dividing the total applicable transportation cost by the
number of clean coal tons resulting from washing the raw coal
transported.
 (f) You must express transportation allowances for coal as a
dollar-value equivalent per short ton of coal transported. If you do
not base your or your affiliate's payments for transportation under a
transportation contract on a dollar-per-unit basis, you must convert
whatever consideration that you or your affiliate paid to a dollar-
value equivalent.
 (g) ONRR may determine your transportation allowance if:
 (1) There is misconduct by or between the contracting parties;
 (2) ONRR determines that the consideration that you or your
affiliate paid under an arm's-length transportation contract does not
reflect the reasonable cost of the transportation because you breached
your duty to market the coal for the mutual benefit of yourself and the
lessor by transporting your coal at a cost that is unreasonably high;
or
 (3) ONRR cannot determine if you properly calculated a
transportation allowance under Sec. 1206.461 or 1206.462 for any
reason, including, but not limited to, your or your affiliate's failure
to provide documents that ONRR requests under 30 CFR part 1212, subpart
E.
0
35. Revise Sec. 1206.461 to read as follows:
Sec. 1206.461 How do I determine a transportation allowance if I
have an arm's-length transportation contract?
 (a) If you or your affiliate incur(s) transportation costs under an
arm's-length transportation contract, you may claim a transportation
allowance for the reasonable, actual costs incurred for transporting
the coal under that contract.
 (b) You must be able to demonstrate that your or your affiliate's
contract is at arm's-length.
 (c) If you have no written contract for the arm's-length
transportation of coal, then you must propose to ONRR a method to
determine the allowance using the procedures in Sec. 1206.458(a). You
may use that method to determine your allowance until ONRR issues a
determination.
 (1) You must use that method to determine your allowance until ONRR
issues a determination.
 (2) [RESERVED]
0
36. Revise Sec. 1260.467 to read as follows:
Sec. 1206.467 What general washing allowance requirements apply to
me?
 (a)(1) If you determine the value of your coal under Sec.
1206.452, you may take a washing allowance for the reasonable, actual
costs to wash the coal. The allowance is a deduction when determining
coal royalty value for the costs that you incur to wash coal.
 (2) You do not need ONRR's approval before reporting a washing
allowance.
 (b) You may not:
 (1) Take an allowance for the costs of washing lease production
that is not royalty bearing.
 (2) Disproportionately allocate washing costs to Federal leases.
You must allocate washing costs to washed coal attributable to each
Federal lease by multiplying the input ratio determined under Sec.
1206.451(e)(2)(i) by the total allowable costs.
 (c)(1) You must express washing allowances for coal as a dollar-
value equivalent per short ton of coal washed.
 (2) If you do not base your or your affiliate's payments for
washing under an arm's-length contract on a dollar-per-unit basis, you
must convert whatever consideration that you or your affiliate paid to
a dollar-value equivalent.
 (d) ONRR may direct you to modify your washing allowance if:
 (1) There is misconduct by or between the contracting parties;
 (2) ONRR determines that the consideration that you or your
affiliate paid under an arm's-length washing contract does not reflect
the reasonable cost of the washing because you breached your duty to
market the coal for the mutual benefit of yourself and the lessor by
washing your coal at a cost that is unreasonably high; or
 (3) ONRR cannot determine if you properly calculated a washing
allowance under Sec. Sec. 1206.467 through 1206.469 for any reason,
including, but not limited to, your or your affiliate's failure to
provide documents that ONRR requests under 30 CFR part 1212, subpart E.
 (e) You may only claim a washing allowance when you sell the washed
coal and report and pay royalties.
0
37. Revise Sec. 1206.468 to read as follows:
Sec. 1206.468 How do I determine washing allowances if I have an
arm's-length washing contract or no written arm's-length contract?
 (a) If you or your affiliate incur(s) washing costs under an arm's-
length washing contract, you may claim a washing allowance for the
reasonable, actual costs incurred.
 (b) You must be able to demonstrate that your or your affiliate's
contract is arm's-length.
 (c) If you have no written contract for the arm's-length washing of
coal, and neither you nor your affiliate perform your own washing, you
must propose to ONRR a method to determine the washing allowance using
the procedures in Sec. 1206.458(a).
 (1) You may use that method to determine your allowance until ONRR
issues a determination.
 (2) [RESERVED]
[[Page 62092]]
PART 1241--PENALTIES
0
38. The authority citation for part 1241 continues to read as follows:
 Authority: 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.; 43
U.S.C. 1301 et seq., 1331 et seq., 1801 et seq.
Subpart A--General Provisions
0
39. Revise Sec. 1241.11 to read as follows:
Sec. 1241.11 Does my hearing request affect a penalty?
 (a) If you do not correct the violation identified in a Notice, any
penalty will continue to accrue, even if you request a hearing, except
as provided in paragraph (b) of this section.
 (b) Standards and procedures for obtaining a stay. If you request
in a timely manner a hearing on a Notice, you may petition the DCHD to
stay the assessment or accrual of penalties pending the hearing on the
record and a decision by the ALJ under Sec. 1241.8.
 (1) You must file your petition for stay within 45 calendar days
after you receive a Notice.
 (2) You must file your petition for stay under 43 CFR 4.21(b), in
which event:
 (i) We may file a response to your petition within 30 days after
service.
 (ii) The 45-day requirement set out in 43 CFR 4.21(b)(4) for the
ALJ to grant or deny the petition does not apply.
 (3) If the ALJ determines that a stay is warranted, the ALJ will
issue an order granting your petition, subject to your satisfaction of
the following condition: Within 10 days of your receipt of the order,
you must post a bond or other surety instrument using the same
standards and requirements as prescribed in 30 CFR part 1243, subpart
B; or demonstrate financial solvency using the same standards and
requirements as prescribed in 30 CFR part 1243, subpart C, for any
specified, unpaid principal amount that is the subject of the Notice,
any interest accrued on the principal, and the amount of any penalty
set out in a Notice accrued up to the date of the ALJ order
conditionally granting your petition.
 (4)(i) If you satisfy the condition to post a bond or surety
instrument or demonstrate financial solvency under paragraph (b)(3) of
this section, the accrual of penalties will be stayed effective on the
date of the ALJ's order conditionally granting your petition.
 (ii) If you fail to satisfy the condition to post a bond or surety
instrument or demonstrate financial solvency under paragraph (b)(3) of
this section, penalties will continue to accrue.
Subpart C--Penalty Amount, Interest, and Collections
0
40. Revise Sec. 1241.70 to read as follows:
Sec. 1241.70 How does ONRR decide the amount of the penalty to
assess?
 (a) ONRR will determine the amount of the penalty to assess by
considering:
 (1) The severity of the violation.
 (2) Your history of noncompliance.
 (3) The size of your business. To determine the size of your
business, we may consider the number of employees in your company,
parent company or companies, and any subsidiaries and contractors.
 (b) For payment violations only, we will consider the unpaid,
underpaid, or late payment amount in our analysis of the severity of
the violation.
 (c) We will post the FCCP and ILCP assessment matrices and any
adjustments to the matrices on our website.
 (d) After we provisionally determine the civil penalty amount using
the criteria and matrices described in paragraphs (a), (b), and (c) of
this section, we may adjust the penalty amount in the FCCP or ILCP
upward or downward if we find aggravating or mitigating circumstances.
 (1) Aggravating circumstances may include, but are not limited to:
 (i) Committing a violation because you determined that the cost of
a potential penalty is less than the cost of compliance; and
 (ii) Committing a violation where you have no recent history of
noncompliance of the same type, but you have a history of noncompliance
of other violation types.
 (iii) Committing a violation that is also a criminal act.
 (2) Mitigating circumstances may include, but are not limited to:
 (i) Operational impacts resulting from the unexpected illness or
death of an employee, natural disasters, pandemics, acts of terrorism,
civil unrest, or armed conflict;
 (ii) Delays caused by government action or inaction, including as a
result of a government shutdown and ONRR-system downtime; and
 (iii) Good faith efforts to comply with formal or informal agency
guidance.
[FR Doc. 2020-17513 Filed 9-30-20; 8:45 am]
 BILLING CODE 4335-30-P