Appellate Case: 21-2011 Document: 010110678144 Date Filed: 05/02/2022 Page: 1
FILED
United States Court of Appeals
PUBLISH Tenth Circuit
UNITED STATES COURT OF APPEALS May 2, 2022
Christopher M. Wolpert
FOR THE TENTH CIRCUIT Clerk of Court
_________________________________
OXY USA INC.,
Plaintiff - Appellant,
v. No. 21-2011
UNITED STATES DEPARTMENT OF
THE INTERIOR; OFFICE OF NATURAL
RESOURCES REVENUE; GREGORY
GOULD, in his official capacity as
Director of the Office of Natural Resources
Revenue,
Defendants - Appellees.
_________________________________
Appeal from the United States District Court
for the District of New Mexico
(D.C. No. 1:19-CV-00151-KWR-JHR)
_________________________________
James M. Auslander (Peter J. Schaumberg, with him on the briefs), Beveridge &
Diamond, P.C., Washington, DC, appearing for Appellant.
Andrew M. Bernie, Attorney (Todd Kim, Assistant Attorney General, and John Smeltzer,
Attorney, with him on the brief), United States Department of Justice, Environment and
Natural Resources Division, Washington, DC, appearing for Appellees.
_________________________________
Before HOLMES, BRISCOE, and MORITZ, Circuit Judges.
_________________________________
BRISCOE, Circuit Judge.
_________________________________
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This case concerns the valuation of royalties to be paid on carbon dioxide
(“CO2”) produced from federal oil and gas leases now owned by OXY USA, Inc.
(“OXY”). OXY appeals the decision of the U.S. Department of the Interior’s Office
of Natural Resources Revenue (“ONRR”) ordering it to pay an additional
$1,820,652.66 in royalty payments on federal gas leases that are committed to the
Bravo Dome Unit (“the Unit”). Under the Mineral Leasing Act, federal lessees must
pay royalties of at least 12.5 percent on the value of the CO2 removed or sold from
their lease properties. When lessees sell their gas in arm’s-length transactions, 1 the
sales price can generally be used to determine value for royalty purposes. But during
the relevant audit period, the owner of the leases OXY subsequently acquired—
Amerada Hess Corporation (“Hess”)—used almost all of the CO2 it produced in the
Unit for its own purposes rather than sale. 2
Following an audit, ONRR rejected Hess’s valuation method and established
its own. Hess appealed, and ONRR’s Director issued a decision reducing the amount
Hess owed but affirming the remainder of ONRR’s order. Hess appealed to the
1
Arm’s-length transactions involve contracts or agreements that have been
arrived at in the marketplace between independent, nonaffiliated persons with
opposing economic interests regarding those contracts. 30 C.F.R. § 206.151.
2
During the relevant audit period, Hess was the lessee of the federal leases at
issue in this appeal. OXY obtained the leases from Hess in 2017, after ONRR’s
order was issued. Unless otherwise indicated herein, we refer to Hess for time
periods before 2017 and to OXY for later periods. Beyond the leases OXY acquired
from Hess, OXY holds other federal Unit leases, but they are not at issue in this case
because the agency’s decision does not cover them.
2
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Interior Board of Land Appeals, but the Board did not issue a final merits decision
prior to the 33-month limitations period. On appeal to the United States District
Court for the District of New Mexico, the district court rejected OXY’s challenge to
the amount of royalties owed and affirmed the Director’s decision.
Exercising jurisdiction under 28 U.S.C. § 1291, we affirm.
I
A. Statutory and Regulatory Background
1. Mineral Leasing Act of 1920 and Federal Oil and Gas Royalty
Management Act of 1982
The Mineral Leasing Act of 1920 regulates the leasing of public lands for
developing deposits of federally owned coal, petroleum, natural gas, and other
minerals. 30 U.S.C. § 181 et seq. Lessees must pay a royalty “at a rate of not less
than 12.5 percent in amount or value of the production removed or sold from the
lease.”
30 U.S.C. § 226(b)(1)(A).
In 1982, Congress passed the Federal Oil and Gas Royalty Management Act in
order “to ensure the prompt and proper collection and disbursement of oil and gas
revenues.” H.R. Rep. No. 97-859, at *1 (1982). The Act directs the Secretary of the
Interior to “establish a comprehensive inspection, collection and fiscal and
production accounting and auditing system” to determine and collect oil and gas
royalties. 30 U.S.C. § 1711(a). The Secretary of the Interior also is required to
“audit and reconcile, to the extent practicable, all current and past lease accounts for
3
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leases of oil or gas and take appropriate actions to make additional collections or
refunds as warranted.” § 1711(c)(1).
2. ONRR’s 1988 Valuation Regulations
The regulations in effect during the relevant period were issued by the Interior
Department’s Minerals Management Service in 1988 and codified at 30 C.F.R.
§ 206. 3 See
53 Fed. Reg. 1230 (Jan. 15, 1988). The regulations provide that with
narrow exceptions, if a lessee disposed of its production pursuant to an arm’s-length
contract, the gross proceeds accruing to the lessee under that contract determine the
value of the gas for royalty purposes.
30 C.F.R. §§ 206.152(b)(1)(i)–(iv). For gas
production not disposed of pursuant to an arm’s-length contract, the lessee must
value its gas pursuant to the “first applicable” of three possible benchmarks:
(1) The gross proceeds accruing to the lessee pursuant to a sale under its
non-arm’s-length contract (or other disposition other than by an
arm’s-length contract), provided that those gross proceeds are
equivalent to the gross proceeds derived from, or paid under,
comparable arm’s-length contracts for purchase, sales, or other
dispositions of like-quality gas in the same field (or, if necessary to
obtain a reasonable sample, from the same area). In evaluating the
comparability of arm’s-length contracts for the purposes of these
regulations, the following factors shall be considered: price, time of
execution, duration, market or markets served, terms, quality of gas,
volume, and such other factors as may be appropriate to reflect the
value of the gas.
3
In 2010, ONRR replaced the Minerals Management Service, and the
regulations at 30 C.F.R. § 206 were redesignated as
30 C.F.R. § 1206 without
material change. See
75 Fed. Reg. 61,051 (Oct. 4, 2010). The regulations have since
been amended further and are the subject of both litigation and additional proposed
rulemaking, but none of these subsequent developments are relevant to this case. For
consistency, we cite to the 1988 regulations using the
30 C.F.R. § 206 citations.
4
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(2) A value determined by consideration of other information relevant in
valuing like-quality gas, including gross proceeds under arm’s-length
contracts for like-quality gas in the same field or nearby fields or areas,
posted prices for gas, prices received in arm’s-length spot of sales of
gas, other reliable public sources of price or market information, and
other information as to the particular lease operation or the saleability of
the gas; or
(3) A net-back method or any other reasonable method to determine
value.
§§ 206.152(c)(1)–(3). Put another way, if gas is not sold pursuant to an arm’s-length
contract but is sold pursuant to an equivalent non-arm’s-length contract, the lessee
must value its gas pursuant to the first regulatory benchmark. 4 If gas is not sold
pursuant to an arm’s-length contract or an equivalent non-arm’s-length contract (as
in OXY’s case), a lessee must turn to the second regulatory benchmark, which is
more open-ended. § 206.152(c)(2).
After a lessee calculates the value of gas, ONRR allows the lessee to take a
transportation allowance, or “a deduction for the reasonable actual costs incurred by
the lessee to transport unprocessed gas, residue gas, and gas plant products from a
lease to a point off the lease.” § 206.156(a). The regulations clarify that “[t]he
lessee must place gas in marketable condition . . . at no cost to the Federal
Government,” which means that the lessee cannot include the costs required to place
the gas in marketable condition in the transportation allowance. § 206.152(i)
4
The parties do not dispute ONRR’s conclusion that the first regulatory
benchmark does not apply because Hess took the majority of its CO2 production from
the Unit in-kind and did not accrue gross proceeds under a non-arm’s-length contract.
5
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(emphasis added). All transportation allowances deducted under a non-arm’s-length
or no contract situation are subject to ONRR’s monitoring, review, audit, and
adjustment, and the agency “may direct a lessee to modify its estimated or actual
transportation allowance deduction.” § 206.157(b).
In determining a non-arm’s-length transportation allowance, a lessee also may
include certain “allowable costs.” § 206.157(f). The regulations directly address the
two costs at issue in OXY’s case: compression and dehydration. 5 The regulations
allow a lessee to include “[s]upplemental costs for compression, dehydration, and
treatment of gas . . . only if such services [1] are required for transportation and
[2] exceed the services necessary to place production into marketable condition.”
§ 206.157(f)(9) (emphasis added).
All royalty payments then are subject to ONRR’s audit and adjustment, and
ONRR “will direct a lessee to use a different value if it determines that the reported
value is inconsistent with the requirements of these regulations.” §§ 206.150(c),
206.152(e)(1).
An important feature of the regulations at issue in this case is that “[i]f the
specific provisions of any [Federal oil or gas lease] . . . are inconsistent with any
regulation [applicable to the gas production from Federal oil and gas leases], then the
lease . . . shall govern to the extent of that inconsistency.” § 206.150(b). The
5
Compression and dehydration are processes that remove unacceptable liquids
and impurities from natural gas extracted from the ground and prepare the gas for
safe transport and use.
6
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regulations explain that their purpose “is to establish the value of production for
royalty purposes consistent with . . . lease terms” and they “are intended to ensure
that the administration of oil and gas leases is discharged in accordance with the
requirements of the governing mineral leasing laws and lease terms.” §§ 206.150(a),
(d). In short, the relevant regulations are meant to be applied as follows: If the
regulation is inconsistent with a lease, then the lease governs to the extent of that
inconsistency.
B. Factual and Procedural Background
1. The Bravo Dome Unit and Unit Agreement
Hess produced CO2 from numerous federal leases (“Leases”) in Harding,
Quay, and Union Counties in northern New Mexico. 6 Under the Leases’ terms, Hess
agreed to pay the United States, as lessor, “12 ½ percent royalty on the production
removed or sold from the leased lands computed in accordance with the Oil and Gas
Operating Regulations (30 C.F.R. Pt. 221).” ROA, at 442b, 446b, 450b, 454b
[Sec. 2(d)(l)]. The Leases further state:
It is expressly agreed that the Secretary of the Interior may establish
reasonable minimum values for purposes of computing royalty on any
or all oil, gas, natural gasoline, and other products obtained from gas,
due consideration being given [1] to the highest price paid for a part or
for a majority of production of like quality in the same field, [2] to the
price received by the lessee, [3] to posted prices, and [4] to other
relevant matters and, whenever appropriate, after notice and opportunity
to be heard.
6
The record contains a total of four Leases, and their relevant terms are
identical. See ROA, at 442, 446, 450, 454.
7
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Id. [Sec. 2(d)(2)] (“Lease valuation factors”). The Leases clarified that Hess was
“subject to any unit agreement heretofore or hereafter approved by the Secretary of
the Interior, the provisions of said agreement to govern the lands subject thereto
where inconsistent with the terms of this lease.” Id. at 442a, 446a, 450a, 454a
[Sec. 1].
Bravo Dome is a natural carbon source field located in northeastern New
Mexico. In 1979, the Bravo Dome Unit was formed under the Bravo Dome Carbon
Dioxide Unit Agreement (“Unit Agreement”) to consolidate and coordinate CO2
production from a number of both federal and non-federal leases in the Bravo Dome
area, including Hess’s Leases. Id. at 415–40. Under the terms of the Unit
Agreement, once the Unit Operator allocated CO2 to each tract in the Unit, each
working-interest owner 7 remitted payment to its royalty-interest owners. Id. at 429
[§ 6.3]. The original Unit Operator was Amoco Production Company (“Amoco”),
but Amoco’s successor-in-interest OXY was the Unit Operator during the relevant
audit period.
The Unit Agreement modified the underlying Leases to the extent of any
inconsistencies, and it incorporated the federal oil and gas operating regulations
“provided such regulations are not inconsistent with the terms of this Agreement.”
Id. at 417, 424 [§ 3.3], 438 [§ 15.1]. The Unit Agreement also attempted to modify
A working-interest owner is someone who owns the right to search, develop,
7
and produce oil and gas on the leased property as well as pay all costs. ROA, at 219.
8
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the royalty clauses in the Leases committed to the Unit in two ways. First, royalty
was due on CO2 at “the standard conditions of measurement for natural gases which
are at 60° Fahrenheit and 15.025 pounds per square inch absolute [‘psia’] pressure
base.” Id. at 429 [§ 6.2]. Second, the Unit Agreement attempted to amend the
royalty clauses to base royalty payments on the higher of “(a) the net proceeds
derived from the sale of Carbon Dioxide Gas at the well whether such sale is to one
or more of the parties to this agreement or to any other party or parties; or (b) a
minimum value at the well of twelve cents per thousand cubic feet ($0.12/mcf).” Id.
[§ 6.3].
For the Unit Agreement to be effective, Amoco was required to submit it to the
United States Geological Survey (“USGS”) for approval. 8 On August 29, 1980,
USGS approved the Unit Agreement, with a few exceptions. Id. at 465. In the
Determination approving the Unit Agreement, USGS certified that the Unit
Agreement modified the Leases’ terms to the extent of any inconsistencies. Id. But
USGS excluded some provisions of the Unit Agreement from its approval, the
relevant exclusion being § 6.3(b)—the twelve cents per thousand cubic feet minimum
value. Id. The Determination stated that “the provisions of Article 6.3(b) shall not
apply to the Federal lands and the United States reserves the right to establish higher
8
In 1980, when the Unit was formed, the applicable regulations required a
supervisor of the USGS to approve unit agreements. The supervisor was required to
make a determination that the unit was necessary or advisable in the public interest
and was for the purpose of conserving the natural resource. See 30 U.S.C. § 226.8
(1980); ROA, at 220.
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minimum values for Federal substances.” Id. Therefore, the approved Unit
Agreement required federal lessees to pay royalties on the higher of either (1) the net
proceeds derived from the sale of CO2 gas at the well, or (2) a minimum value
established by the United States.
Id. at 429 [§ 6.3], 465.
2. Hess Operations and Royalty Payments
Hess owned approximately ten percent of the working interest in the Unit since
it was formed. During the relevant audit period, Hess sold a small percentage of the
CO2 it produced from the Unit under an arm’s-length contract with Fasken Oil and
Ranch, Ltd. (“Fasken Contract”). Id. at 222. Hess had no other sales of CO2 during
the relevant period. Id. at 224. Hess instead used the vast majority of the CO2
allocated to its Leases for its own use in enhanced oil recovery (“EOR”) projects in
the Permian Basin in West Texas and New Mexico. 9 Id. at 223–24. In addition to
sourcing its own CO2 from the Unit, Hess also purchased a large volume of CO2 from
other Unit working-interest owners to use in its EOR operations (“Hess Purchase
Contracts”). Id.
To transport the CO2 from the Unit to the Permian Basin EOR units, Hess first
transported the CO2 through the Rosebud Pipeline and Sheep Mountain Pipeline to a
9
Enhanced oil recovery is the extraction of crude oil from an oil field that
cannot be extracted otherwise. The process involves injecting liquified CO2 into the
pore space of reservoir rock to help displace oil and drive it to a production wellbore.
At the surface, the CO2 is separated from the oil, the oil is sold, and the CO2 is reused
again in the EOR reservoir. This means that the CO2 used in EOR operations is part
of a continual process and is not sold. See, e.g., ROA, at 223–24.
10
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hub in Denver City, Texas (“Denver Hub”). Id. at 221. From the Denver Hub, Hess
transferred the CO2 into two other pipelines for delivery into the Permian Basin EOR
units. Id. Each step of transportation required the CO2 to be at a particular pressure.
The wellhead pressure of the CO2 in the Unit ranged from 16 to 78 pounds per square
inch gauge (“psig”), but the pressure necessary to enter the Rosebud Pipeline was
1,850 psig. Id. Accordingly, before the CO2 could enter the Rosebud Pipeline, Hess
gathered the CO2 on the Unit and compressed it to 1,850 psig. Along the route to the
Permian Basin EOR units, the pressure of the CO2 again was appropriately adjusted
to meet the varying pressure requirements: 1,925 psig at the interconnect between the
Rosebud Pipeline and Sheep Mountain Pipeline; 2,150 psig at the outlet of the Sheep
Mountain Pipeline at the Denver Hub; and upwards of 2,500 psig to enter the
Permian Basin EOR units. Id. at 221–22.
To comply with the applicable laws, Hess was required to value its CO2
production for royalty purposes. Because Hess transported the majority of its federal
CO2 production to the Permian Basin EOR units (only a small percentage went to the
Fasken Contract) and the CO2 continued to be reused in the Permian Basin EOR
units, Hess had no other sales of CO2 to use as reference for royalty valuation. Id.
at 224. During the audit period, Hess paid royalties based on “the Unit Average,”
which the Unit Operator provided lessees on a monthly basis using a “netback
approach.” Id. Under the netback approach, the Unit Operator determined the Unit
Average by taking the price or value lessees in the Unit received for their sale of the
CO2 at the Denver Hub. Id. The Unit Operator then deducted transportation costs
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from those values and prices to arrive at a value for the CO2 removed at the Unit. Id.
Hess reported these prices as the basis of its royalty payments throughout the audit
period. Id.
Beginning in March 2004, Hess also started reporting the compression and
dehydration costs it incurred for delivery to the Permian Basin EOR units as a
transportation allowance. Id. Hess reported compression and dehydration costs in
the amount of $806,290.73 during the audit period. Id. at 276.
3. Smithson Litigation and Arbitration Decision
During the audit period, Hess also was a working-interest owner and operator
in some of the EOR units in West Texas. Id. at 222. In 2006, a group of private
lease royalty owners sued Hess in the District of New Mexico, alleging that Hess
undervalued royalties by intentionally negotiating lower prices for the CO2 in its
purchase contracts and then using that lower price to value its in-kind sales to
determine the amount of royalties it owed. See Smithson v. Amerada Hess Corp.,
No. 06-624-MCA (D.N.M. 2006).
The matter proceeded to arbitration. A three-member arbitration panel
determined that from October 2003 through December 2008, Hess had breached its
duty of good faith and fair dealing to the royalty owners by obtaining the lowest
fixed price possible for CO2 and using this “improper benchmark” to value its in-kind
sales to them. ROA, at 351. To calculate a proper price, the panel “considered the
numerous options of benchmarks and methodologies offered by the parties at the
arbitration,” as well as the trove of evidence the parties provided that included
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contracts and relevant pricing mechanisms. Id. at 353, 356–66. The panel also
considered the testimony of Hess’s valuation specialist, who indicated that the proper
formula “should be reflective of the market conditions in the fall of 2003, as well as
reflecting the historical contracting practices from the . . . pool of contracts [that the
parties provided].” Id. at 274. The panel ultimately determined that “the ‘blend’ of
the 2 methods suggested by [Hess’s valuation specialist] . . . [was] the proper
benchmark for the applicable period” (“the Smithson formula”). Id.; see also id.
at 356–66 (detailing the Smithson formula).
Hess sought vacatur of the arbitration panel’s decision, but the parties then
entered a settlement agreement. Id. at 263–69. In March 2010, the district court
approved the settlement agreement. Id. at 489–94.
4. New Mexico Audit
Pursuant to 30 U.S.C. § 1735, ONRR delegated authority to audit Hess’s
royalty reports and payments for the period of January 1, 2002, to November 30,
2010, to New Mexico’s Taxation and Revenue Department (“New Mexico”).
On September 22, 2009, New Mexico sent Hess an initial audit issue letter
stating that Hess owed an additional $1,458,127.94 for the period of January 2002
through December 2005. Id. at 292–97. The letter suggested that the third regulatory
benchmark applied (the net-back method,
30 C.F.R. § 206.152(c)(3)) and valued
Hess’s CO2 based on the single arm’s-length Fasken Contract.
Id. at 295.
New Mexico then corresponded with ONRR regarding Hess’s CO2 valuation
and allowable transportation deductions. On January 12, 2011, ONRR sent New
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Mexico a response letter. Id. at 407–11. In the response letter, ONRR explained that
although the Minerals Management Service had in the past directed the Unit’s
producers to value their gas based on the Unit Average, “under different market
scenarios and dispositions of Bravo Dome production, it does not dictate how value
for royalty purposes must be established during later time periods.”
Id. at 410. In
doing so, ONRR noted that the Unit Average “falls short” because CO2 values
determined by other Unit producers, including non-federal lessees, would not
necessarily be relevant and ONRR could not easily verify whether such valuations
met federal requirements.
Id.
ONRR went on to explain that “absent lack of significant arm’s-length sales in
the Bravo Dome field, royalty value must be determined in the Permian Basin EOR
units where there is an established market for CO2”—i.e., where Hess ultimately used
the CO2. Id. But ONRR observed that Hess purchased large quantities of CO2 for its
own use and on behalf of other working-interest owners in its Permian Basin EOR
operations.
Id. Hess therefore had “far more incentive to obtain the lowest possible
price for CO2 used in its Permian Basin EOR Units than it [did] to obtain a reasonable
value for the government’s royalty share of CO2 from the Bravo Dome Unit” and was
arguably “able to depress the market price of CO2 in order to obtain the highest
possible return on its Permian Basin oil production.”
Id. Consequently, ONRR
concluded that the Smithson formula was a reasonable valuation under the second
regulatory benchmark.
Id. (citing
30 C.F.R. § 206.152(c)(2)).
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Regarding whether Hess’s compression and dehydration costs could be
deducted as a transportation allowance, ONRR determined that “since the Permian
Basin [where Hess used the CO2 in EOR units] is the market for Bravo Dome CO2,
the requirements to place CO2 into marketable condition would be established there.”
Id. at 411. This meant that “[a]ny costs incurred to compress the CO2 up to [the
required pressure for injection at the Permian Basin EOR units] would not be
deductible from royalties as a transportation allowance.”
Id.
On February 1, 2011, New Mexico sent Hess a revised issue letter that was
generally consistent with ONRR’s January 12, 2011 letter. Id. at 285–91. The
revised letter acknowledged that although the Unit Average valuation method “may
have been acceptable in the past under different market scenarios and dispositions of
Bravo Dome production, it does not dictate how value for royalty purposes must be
established during the later periods.”
Id. at 286. In Hess’s case, the lack of
arm’s-length sales of significant volumes in the Bravo Dome field meant that
“royalty value must be determined in the Permian Basin EOR units where there is an
established market for CO2.”
Id. at 286–87. The revised letter further explained that
because Hess did not dispose of the majority of its CO2 under arm’s-length contracts,
Hess should value its production using the Smithson formula under the second
regulatory benchmark.
Id. Regarding transportation deductions, the revised letter
stated that “[c]ompression and dehydration costs are costs to get the CO2 gas to
marketable condition needed for EOR production,” so Hess could not deduct the
costs incurred to compress the CO2 up to the pressure requirement for the EOR
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delivery pipelines as a transportation allowance. Id. at 288. The revised letter also
expanded the audit period to run from January 1, 2002, through November 30, 2010.
Id. at 285.
On March 11, 2011, Hess responded to the revised issue letter and raised
arguments regarding valuation and marketable condition. Id. at 276–79. After
reviewing Hess’s response, New Mexico reevaluated its proposed valuation method
but adhered to its position that the Unit Average was an inappropriate valuation
method and that Hess’s claimed compression and dehydration costs were not
deductible as a transportation allowance.
Id. at 225–26.
5. Administrative Proceedings
On December 19, 2011, ONRR issued an Order to Report and Pay Additional
Royalties based on New Mexico’s audit that ordered Hess to report and pay
additional royalties of $1,874,524.54 for the audit period of January 1, 2002, through
November 30, 2010. Id. at 270–82. Additionally, in its royalty reports, Hess had
reported CO2 volumes based on a pressure base of 15.025 psia in accordance with the
terms of the Unit Agreement.
Id. at 429 [§ 6.2]. The Order required Hess to correct
its royalty reports to report CO2 volumes based on a pressure base of 14.73 psia in
accordance with the 1988 regulations. See
30 C.F.R. § 202.152.
In the Order, ONRR explained that Hess’s use of the Unit Average price to
value its CO2 production was unacceptable because no mechanism was in place to
verify (1) if the Unit sales price reported by all producers to the Unit Operator was in
accordance with federal regulations; (2) how the price was derived from producers;
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(3) if producers reduced their reported Unit prices, as provided to the Unit Operator,
by the cost of placing the CO2 production into marketable condition; (4) if calculated
transportation costs were in accordance with federal regulations; or (5) if all federal
lessees were using the Unit Average price when paying royalties. Id. at 272. Put
simply, ONRR rejected Hess’s supplied Unit Average valuation because it included
unverified arm’s-length and non-arm’s-length sales.
ONRR then outlined how Hess was required to value its CO2 production for
royalty purposes. The majority of the CO2 that Hess produced (more than 99%) was
transported for use in the Permian Basin EOR units, and while Hess sold a de
minimus volume of CO2 under the single arm’s-length Fasken Contract, “the gross
proceeds were not equivalent to the gross proceeds derived from, or paid under,
comparable arm’s-length contracts.” Id. at 271. Taking this into consideration along
with the variability of pricing mechanisms present in the Hess Purchase Contracts,
ONRR directed the use of the following valuations for the audit period:
• January 2002–September 2003 & April 2008–November 2010: The
best representation of value for these periods was a “weighted average,”
which included only Hess’s verified purchases of CO2 in the Permian
Basin as well as the Fasken Contract.
• October 2003–March 2008: The best representation of value for this
period was the Smithson formula because this formula was based on
transparent, reliable, and relevant evidence including expert testimony
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from Hess’s valuation specialist and CO2 purchase contracts, pricing
mechanisms, and historical contracting practices from this time. 10
Id. at 273–74.
ONRR further agreed with New Mexico’s conclusion that Hess could not
deduct its compression and dehydration costs as a transportation allowance. Id.
at 275–76. ONRR observed that the pressure required for CO2 delivery along the
pipelines to the Permian Basin did not exceed the pressure requirements for use in the
Permian Basin EOR units, plus typical sales or purchases contracts for the Unit’s
CO2 production also contained these pressure requirements as a condition for use in
the Permian Basin EOR units.
Id. at 275. The costs of compression and dehydration
up to the EOR requirements, ONRR reasoned, therefore were costs of placing the
CO2 into marketable condition.
Id. ONRR noted that substantial case law supported
its position to disallow the costs of compression and dehydration necessary to meet
pressure requirements for CO2 delivery to EOR operations.
Id. at 276 (citing Devon
Energy Corp. v. Kempthorne,
551 F.3d 1030, 1036–40 (D.C. Cir. 2008), and Amoco
Prod. Co. v. Watson,
410 F.3d 722, 729–31 (D.C. Cir. 2005), aff’d sub nom., BP Am.
Prod. Co. v. Burton,
549 U.S. 84 (2006)). Hess appealed the Order to ONRR’s
Director.
Id. at 218.
10
OXY asserts that ONRR “ordered Hess to use three different values for the
same CO2 during the Audit Period,” but the record shows that the agency directed the
use of only two values: the “weighted average” and the Smithson formula. Compare
Aplt. Br. at 12 with ROA, 273–74.
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On September 13, 2016, ONRR’s Director issued a decision, which largely
affirmed the agency’s Order to Report and Pay Additional Royalties. Id. at 217–54.
The Director determined that ONRR reasonably established a minimum value for
Hess to use to calculate the value of its federal CO2 production based on Hess’s gross
proceeds under the Fasken Contract, the price that Hess purchased CO2 from other
lessees, and the Smithson formula. In reaching this conclusion, the Director found
that ONRR never had required Hess to only use the Unit Average valuation and that
the terms of the Unit Agreement and underlying Leases actually allowed ONRR,
independent of the 1988 regulations, to establish a reasonable value for Hess’s CO2
within the bounds of the Lease valuation factors.
Id. at 227–28, 248–53. But the
Director also analyzed ONRR’s valuation under the applicable 1988 regulations,
specifically the second regulatory benchmark, and determined that the result would
be the same.
Id. at 239–43. The Director then determined that ONRR properly
denied Hess’s claimed compression and dehydration costs as a transportation
allowance because these costs were necessary to place the CO2 in marketable
condition.
Id. at 243–47.
Lastly, regarding the pressure base calculation, the Director realized that the
regulations and Unit Agreement were in conflict on this point. Id. at 247–48. In
1980, when USGS approved the Unit Agreement, the regulations required lessees to
base royalty payments on “10 ounces above an atmospheric pressure of 14.4 pounds
to the square inch, regardless of the atmospheric pressure at the point of
measurement.”
Id. (citing
30 C.F.R. § 221.44 (1980)). The regulations required
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lessees to adjust their royalty computation to those standards “unless otherwise
authorized in writing by the supervisor.” Id. Because USGS approved the Unit
Agreement in writing and the Unit Agreement required Hess to remit royalties on
CO2 volumes at a pressure base on 15.025 psia, the Director determined that Hess
needed to report and pay royalties on volumes at the 15.025 psia pressure base.
Id.
The Director applied the correct pressure base and reduced the royalty amount due
accordingly. 11
Id.
Hess appealed to the Interior Board of Land Appeals, which exercises the
Secretary of the Interior’s de novo review authority for subordinate agency decisions.
Id. at 330. The Board did not issue a final merits decision prior to the 33-month
limitations period. See
30 U.S.C. § 1724(h)(1); ROA, at 321–23. The Director’s
decision thus became the agency’s final decision ripe for judicial review.
30 U.S.C.
§ 1724(h)(2)(B);
43 C.F.R. § 4.906(a).
6. District Court Opinion
OXY then brought this lawsuit, challenging the decision of ONRR’s Director
under the Administrative Procedure Act (“APA”), 5 U.S.C. § 706(2)(A). ROA,
at 19–22. Applying the appropriate deferential standard of review, the district court
affirmed the Director’s decision.
Id. at 70–93. The district court first acknowledged
11
The Director reduced the amount due from $1,874,524.54 to $1,820,652.66
(a difference of $53,891.88), which reflects the amount due as a result of previously
requiring Hess to report its CO2 volumes on a 14.73 psia pressure base. ROA,
at 247–48, 253. OXY does not challenge the Director’s calculation of the pressure
base or that the Unit Agreement is controlling in this aspect.
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the Director’s conclusion that ONRR’s valuation was to be assessed under the Lease
valuation factors, and it observed that ONRR had considered the relevant factors and
evidence in establishing a reasonable minimum value and had thoroughly explained
its decision. Id. at 78–84. ONRR also had “appropriately considered and rejected
the Unit Average,” as the Director’s decision “extensively explained why the Unit
Average was not satisfactory and why [the agency] was using a new valuation
method.”
Id. at 84–85.
The district court then considered the Director’s alternative conclusion that
ONRR’s valuation also was reasonable under the second regulatory benchmark. Id.
at 87. Because the Director had analyzed the relevant facts and articulated what
evidence he considered under each regulatory valuation factor, the district court
determined that it “[would] not second-guess the Director’s decision in weighing the
regulatory factors.”
Id.
Finally, regarding whether compression and dehydration costs were deductible
as a transportation allowance, the district court concluded that the Director’s decision
“cogently explain[ed] that the costs are not deductible because they are necessary to
place the carbon dioxide in marketable condition.” Id. at 88. In particular, the
Director’s interpretation and application of the marketable-condition rule to OXY’s
case was “not plainly erroneous or inconsistent with the regulation.”
Id. at 91.
OXY now appeals to this court.
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II
We review the district court’s decision in APA cases de novo. N.M. Cattle
Growers Ass’n v. Fish & Wildlife Serv., 248 F.3d 1277, 1281 (10th Cir. 2001).
Under the APA, we may set aside agency action only if it is “arbitrary, capricious, an
abuse of discretion, or otherwise not in accordance with law.”
5 U.S.C. § 706(2)(A).
An agency’s decision is arbitrary and capricious if the agency (1) “entirely failed to
consider an important aspect of the problem,” (2) “offered an explanation for its
decision that runs counter to the evidence before the agency, or is so implausible that
it could not be ascribed to a difference in view or the product of agency expertise,”
(3) “failed to base its decision on consideration of the relevant factors,” or (4) made
“a clear error of judgment.” Utah Env’t Cong. v. Troyer,
479 F.3d 1269, 1280 (10th
Cir. 2007) (internal citations and quotations omitted). Our “inquiry under the APA
must be thorough, but the standard of review is very deferential to the agency.”
Hillsdale Env’t Loss Prevention, Inc. v. U.S. Army Corps of Eng’rs,
702 F.3d 1156,
1165 (10th Cir. 2012).
Under this standard, we ask whether the agency’s interpretation of the
regulations at issue was based on an examination of the relevant evidence and if the
agency “articulated a rational connection between the facts found and the decision
made.” Payton v. U.S. Dep’t of Agric., 337 F.3d 1163, 1168 (10th Cir. 2003). We
may reject the agency’s interpretation only when the interpretation is unreasonable,
plainly erroneous, or inconsistent with the regulation’s plain meaning. Biodiversity
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Conservation All. v. Jiron, 762 F.3d 1036, 1060 (10th Cir. 2014) (citing Utah Env’t
Cong.,
479 F.3d at 1281).
We also “will set aside the [agency’s] factual determinations only if they are
unsupported by substantial evidence.” Forest Guardians v. U.S. Fish & Wildlife
Serv., 611 F.3d 692, 704 (10th Cir. 2010) (alteration in original). Substantial
evidence is such relevant evidence as a reasonable mind might accept as adequate to
support a conclusion. Pennaco Energy, Inc. v. U.S. Dep’t of the Interior,
377 F.3d
1147, 1156 (10th Cir. 2004) (internal citation omitted). The substantial evidence
standard does not allow us to displace the agency’s choice “between two fairly
conflicting views, even though [we] would justifiably have made a different choice
had the matter been before [us] de novo.” Wyo. Farm Bureau Fed’n v. Babbitt,
199 F.3d 1224, 1231 (10th Cir. 2000) (internal quotations omitted).
III
OXY argues on appeal that ONRR’s decision is arbitrary, unsubstantiated, and
internally inconsistent and the district court erred in affirming the agency’s decision.
OXY asserts that ONRR’s Director incorrectly found the agency’s valuation
reasonable under the Lease valuation factors, improperly rejected Hess’s Unit
Average as the valuation method, and misapplied the 1988 regulatory factors to
alternatively affirm the agency’s valuation under the second regulatory benchmark.
OXY further asserts that the Director erred in determining that Hess’s compression
and dehydration costs are not deductible as a transportation allowance.
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We conclude that ONRR’s valuation is not arbitrary or capricious, is supported
by substantial evidence, and is otherwise in accordance with law, and we affirm the
Director’s decision. We will address each of OXY’s contentions in turn.
A. ONRR’s Valuation
We first will consider whether the Director erred in determining that ONRR
reasonably established a minimum value for Hess to use to calculate the value of its
federal CO2 production. ONRR’s valuation used (1) the “weighted average” from
January 2002 to September 2003 and April 2008 to November 2010, and (2) the
Smithson formula from October 2003 to March 2008. ROA, at 273–74.
At the outset of the Director’s decision, the Director noted that the approved
Unit Agreement, along with the underlying Leases, required the federal lessees to pay
royalties on the higher of either (1) the net proceeds derived from the sale of CO2 gas
at the well, or (2) a minimum value established by the United States. Id. at 429
[§ 6.3], 465. Recall that if the applicable 1988 regulation is inconsistent with a lease,
then the lease governs to the extent of that inconsistency.
30 C.F.R. § 206.150(b).
The 1988 regulations authorize a lessee to first compute the minimum royalty value
through the benchmark system, and ONRR is then empowered to determine whether
the lessee’s valuation is inconsistent with the applicable regulations.
§§ 206.152(c)(1)–(3), 206.152(e)(1). In contrast, under the Unit Agreement and
underlying Leases, the Secretary retains the right to establish the royalty value on
CO2 production based on the Lease valuation factors following notice and an
opportunity to be heard when appropriate. After comparing the regulations and the
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Unit Agreement, the Director determined that “[t]he Leases and Unit Agreement
govern the value of Hess’s CO2 for federal royalty purposes” because “the Secretary
retained the right to establish a minimum value for federal CO2 production in the
Unit in its approval of the Unit Agreement.” ROA, at 227–28, 239.
Because Hess did not sell the CO2 production at issue, the Director evaluated
ONRR’s valuation under the Lease valuation factors to see if ONRR had properly
established a reasonable minimum value, after giving Hess notice and an opportunity
to be heard:
(1) The Highest Price Paid for a Part or for a Majority of Production of
Like Quality in the Same Field: The Director explained that federal
lessees in the Unit (holding less than ten percent of an interest in the
Unit) sell less than one percent of the CO2 produced from the federal
lands. Federal lessees use the remainder in their EOR operations.
ONRR only had data for the federal CO2 production and considered that
data set, but the agency reasonably concluded that the data set was too
small to accurately establish a minimum value. ONRR also could not
consider the Hess Purchase Contracts under the first factor because the
agency could not determine whether such contracts represented the
“highest price paid” for a part or majority of production from the Unit.
The Director concluded that ONRR had properly considered this factor.
(2) The Price Hess Received for the CO2: ONRR considered the Fasken
Contract in the context of the “weighted average” calculation, but
because this represented a very small fraction of Hess’s federal CO2
disposition, ONRR determined that it could not solely rely on these
prices alone. The Director concluded that ONRR had properly
considered this factor.
(3) Posted Prices: ONRR could not consider posted prices for CO2
production because no posted prices for CO2 in the Unit existed during
the audit period. The Director concluded that ONRR had properly
considered this factor.
(4) Other Relevant Matters: ONRR considered the Unit Average, the
prices at which Hess purchased CO2 under the Hess Purchase Contracts,
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and pricing mechanisms used in Hess’s settlements and arbitrations,
including the Smithson formula. The Director found that these
considerations were reasonable, as they helped ONRR identify reliable
indicators of value. The Director concluded that ONRR had properly
considered this factor.
Id. at 227–39; see also id. at 442b, 446b, 450b, 454b [Sec. 2(d)(2)]. The Director
concluded overall that there was insufficient information as to the first and third
factors, so ONRR’s reliance on the second and fourth factors to establish its valuation
was reasonable.
In determining that ONRR’s valuation was reasonable, the Director explained
why ONRR’s consideration of the Smithson arbitration was proper: (1) the arbitration
panel found that Hess had negotiated lower fixed prices for its CO2 purchases and
then had used those lower prices to value the CO2 for royalty purposes; (2) Hess “had
the full opportunity to challenge and offer alternatives to the method the arbitration
panel used to calculate value and damages”; and (3) the arbitration panel “used a
formula price that took into account Hess’s argument for a flat price,” as well as the
suggestions of Hess’s valuation specialist. Id. at 236–37.
The Director also explained why Hess’s Unit Average could not be used to
determine the value of Hess’s CO2 production: (1) it was “extremely difficult to
verify the prices under the Unit Average are consistent with federal valuation
requirements”; (2) the Unit Average “results in a value that is less than the price Hess
is willing to pay for CO2”; and (3) the Unit Average likely included prices from
non-arm’s-length CO2 sales. Id. at 234–36, 253. The Director observed that ONRR
and New Mexico had provided Hess ample notice through correspondence that the
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agency was considering a different valuation method than the Unit Average. New
Mexico sent Hess two audit letters indicating that the Unit Average was not an
appropriate basis for Hess to use to value its federal CO2 production, to which Hess
responded. Id. at 238.
The Director further concluded that ONRR never had demanded that Hess use
the Unit Average valuation in perpetuity, as Hess seemed to claim. Id. at 248–53.
Hess argued that ONRR consistently had required Hess to use the Unit Average to
value its CO2 and that the Unit Average originated from an Amoco proposal to
ONRR on how Amoco should value its federal CO2 production from the Unit. Id.
at 248. The Director examined the sources on which Hess relied and explained in
detail that they did not amount to the agency’s endorsement of the Unit Average, but
to the extent they did, any such guidance was based on the facts presented at the time
and did not bind the agency to the Unit Average methodology decades later. Id.
at 248–53.
After analyzing the reasonableness of ONRR’s valuation under the Lease
valuation factors and rejecting the Unit Average, the Director determined that “the
result would be the same even if the federal gas royalty valuation regulations
controlled the outcome of this case.” Id. at 239 (citing 30 C.F.R. § 206.152(c)(2)).
The Director considered ONRR’s valuation under each of the second benchmark
regulatory factors:
(1) The Gross Proceeds Under Arm’s-Length Contracts for Like-Quality
Gas in the Same Field or Nearby Fields or Areas: ONRR considered
the gross proceeds under arm’s-length contracts for like quality gas,
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including the arm’s-length Fasken Contract. The Fasken Contract was
the only contract in the record that ONRR could verify as an
arm’s-length contract. The Director concluded that ONRR had properly
considered this factor.
(2) Posted Prices: ONRR observed that the record did not include any
evidence of posted prices, so the agency could not evaluate this factor.
The Director concluded that ONRR had properly considered this factor.
(3) Prices Received in Arm’s-Length Spot Sales: ONRR observed that the
record did not include any evidence of prices received in arm’s-length
spot sales, so the agency could not evaluate this factor. The Director
concluded that ONRR had properly considered this factor.
(4) Other Reliable Public Sources of Price or Market Information:
ONRR considered the Smithson formula and Hess’s other settlements as
a means to determine value, but as discussed, it determined that the
Smithson formula was a more appropriate and reliable indicator of value
for the period of October 2003 through December 2008. The Director
concluded that ONRR had properly considered this factor.
(5) Other Information Particular to a Lease Operation or Saleability of
the Gas: Here ONRR considered the Hess Purchase Contracts and the
Unit Average that Hess had used as the basis for its royalty payments.
ONRR ultimately concluded that the Hess Purchase Contracts were a
more appropriate indicator of value than the Unit Average and used the
Hess Purchase Contracts as part of its final “weighted average”
valuation. The Director concluded that ONRR had properly considered
this factor.
Id. at 242–43. The Director concluded overall that ONRR had considered every
potential indicator of value in the record under the second regulatory benchmark.
On appeal, OXY raises three issues regarding ONRR’s valuation: (1) the
Director incorrectly concluded that ONRR’s valuation was reasonable under the
Lease valuation factors; (2) the Director improperly rejected Hess’s Unit Average as
the valuation method; and (3) the Director misapplied the 1988 regulatory factors to
alternatively affirm the agency’s valuation under the second regulatory benchmark.
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1. Reasonableness of ONRR’s Valuation
OXY first argues that ONRR’s valuation is unreasonable and arbitrary. While
OXY does not provide any meaningful challenge to ONRR’s consideration of the
Fasken Contract or the Hess Purchase Contracts, OXY repeatedly asserts that
ONRR’s consideration of the Smithson formula was inappropriate because the
arbitration decision did not involve federal leases and only resolved a royalty dispute
between Hess and private lease owners. Aplt. Br. at 11–12, 45–47. In making this
argument, OXY contends that the Smithson formula never had been used to buy or
sell any CO2; the Smithson formula was not legally binding because the parties
settled after arbitration and the Smithson formula was not agreed to in the settlement;
arbitration awards and decisions have no precedential effect in other cases; and the
Smithson formula does not qualify as relevant evidence under the Lease valuation
factors or the 1988 regulatory factors. Id. at 46–49. Relatedly, OXY argues that if
the agency rejected the Unit Average due to the inclusion of non-arm’s-length
transactions, then it should not have considered the Smithson formula because it
included non-arm’s-length transactions. 12
Id. at 43, 49.
12
OXY also argues that ONRR’s valuation is arbitrary and inconsistent
because “[t]he history of this matter involves no less than four administrative
decisions differently valuing [Hess’s] Audit Period CO2 production.” Aplt. Br. at 19
(emphasis in original). OXY characterizes this history as “a vacillating scattershot of
substitute methodologies to re-value [Hess’s CO2 production].” Id. In actuality,
OXY is referencing the aforementioned correspondence that occurred among New
Mexico, ONRR, and Hess during the audit process, and as discussed, the record
shows that ONRR only issued one Order to Report and Pay Additional Royalties on
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We conclude that the Director considered all relevant evidence and provided
sufficient reasoning for each of ONRR’s determinations regarding the valuation.
Under the deferential APA standard, we ask whether the agency’s decision was based
on an examination of the relevant evidence and if the agency “articulated a rational
connection between the facts found and the decision made.” Payton, 337 F.3d
at 1168. The Director’s methodology and detailed explanations certainly pass muster
under the APA’s deferential framework. The agency considered all relevant
information that was reasonably available, including the single arm’s-length Fasken
Contract, the Hess Purchase Contracts, and the Smithson formula for production
occurring between October 2003 and March 2008. ROA, at 233–37. The Director
then articulated a rational connection between the relevant information and ONRR’s
valuation under the Lease valuation factors and weighed the factors accordingly.
Id.
The Director then analyzed the second regulatory benchmark factors at length and
explained why the result would be the same if the regulatory valuation factors
applied. Echoing the district court, we cannot reweigh the evidence, which seems to
be what OXY is requesting.
As to the Smithson formula, the agency was clear that consideration of this
formula was appropriate because the question under both Hess’s Leases and the 1988
regulations—the reasonable value of Hess’s CO2 based on all relevant and reliable
December 19, 2011, which ONRR’s Director then reduced in OXY’s favor on
review. See ROA, at 217–54, 270–82.
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information—was fundamentally the same inquiry that the Smithson arbitration panel
conducted. During the audit, the agency discovered that Hess did not have other
reliable public sources of price or market information for the audit period, except for
the negligible Fasken Contract. The agency realized that the Smithson formula
provided an appropriate and reliable indicator of value from October 2003 through
December 2008 and therefore considered the formula in its analysis of “other
relevant matters” under the Lease valuation factors, as well as under “other reliable
public sources of price or market information” in its alternative analysis of the 1988
regulatory factors. Id. at 227–39, 242–43. As the Director explained, the formula
was the result of a neutral arbitration panel with full transparency into the basis for
the formula price, whereas Hess’s other settlement agreements did not “provide any
information on what was at issue, how the parties came to the formula price, or how
that price pertains to Hess’s CO2 purchases or sales.” Id. at 236. Moreover, the
arbitration panel set the formula price by blending two valuation methodologies
based on expert testimony proffered by each of the parties, and the formula reflected
“market conditions in the fall of 2003, [and] historical contracting practices.” Id.
at 230–37. It was proper for the agency to rely on the Smithson formula, not for its
precedential value, but rather for the relevant and reliable information it provided
about Hess’s CO2 purchase contracts, pricing mechanisms, and historical contracting
practices from this time.
OXY also contends that the Director’s decision to consider ONRR’s valuation
under the Lease valuation factors, instead of only the 1988 regulatory factors,
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warrants reversal because this court’s affirmance “would inject substantial
uncertainty to royalty valuation for thousands of similarly-situated federal oil and gas
[standard-form] leases” and the 1988 regulations “cabin ONRR’s ability to substitute
its own royalty value.” Aplt. Br. at 21–31; Aplt. Reply Br. at 4–5. But the Director’s
decision was clear that it analyzed ONRR’s valuation in OXY’s case under the Lease
valuation factors because the specific Bravo Dome Unit Agreement controlled: The
Secretary “retained the right to establish a minimum value for federal CO2 production
in the Unit in its approval of the [Bravo Dome] Unit Agreement,” which modified
Hess’s underlying standard-form Leases to the extent they were inconsistent with the
Unit Agreement. ROA, at 227–28, 424. The Director applied this same logic to
reduce the pressure base calculation in accordance with the Unit Agreement in
OXY’s favor, which OXY does not dispute. Id. at 247–48. Further, any such
procedural inconsistency authorizing the Secretary to determine royalty valuation in
the first instance in OXY’s case ultimately is irrelevant because (1) the Director
reasonably articulated why the Unit Average is unreliable and (2) the Director
independently analyzed ONRR’s valuation under the second regulatory benchmark in
the alternative and came to the same conclusion. The Director also noted that while
the Order had not explicitly mentioned the Lease valuation factors in its analysis of
the second regulatory benchmark, the valuation factors overlapped, so the agency had
thoroughly considered the Lease valuation factors in the process of analyzing the
second regulatory benchmark. Id. at 228–38.
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Because the Director weighed the relevant factors and evidence and adequately
explained the agency’s decision, ONRR’s valuation is not arbitrary or capricious.
2. Unit Average Valuation
OXY next argues that the Director improperly rejected Hess’s Unit Average as
the valuation method. OXY asserts that ONRR previously had approved the Unit
Average, and while ONRR is not estopped from conducting audits or reexamining a
valuation methodology, the Director’s decision and administrative record do not
clearly support a reversal of the Unit Average. ONRR merely substituted its own
methodology for the Unit Average “to extract more royalty dollars” without actually
finding that the Unit Average was inconsistent with the regulations. Aplt. Br. at 17.
OXY contends that ONRR instead should have conducted additional investigation
into the pricing practices of other Unit entities before rejecting the Unit Average. Id.
at 36–46.
We conclude that the Director’s decision to reject the Unit Average valuation
methodology is not arbitrary or capricious. In order for this court to reverse ONRR’s
decision, we would have to conclude that the agency failed to consider an important
aspect of the problem, offered an explanation for its decision that runs counter to the
evidence before the agency, or failed to base its decision on consideration of the
relevant factors. Utah Env’t Cong., 479 F.3d at 1280. The record presented does not
support our reaching any of these conclusions in this case. ONRR provided a
reasoned basis for rejecting the Unit Average price methodology under the applicable
regulations. ROA, at 234–36. ONRR’s justifications collectively reinforce each
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other: It was reasonable for ONRR to determine that the Unit Average—comprised
primarily of non-federal lessees that are not subject to ONRR’s regulations or
oversight mechanisms, that ONRR cannot audit, and that use valuation
methodologies both largely unknown to ONRR and likely based at least in part on
non-arm’s-length sales—was not an appropriate measure of value, particularly since
the Unit Average resulted in a price lower than the Hess Purchase Contracts that
ONRR was able to examine.
The Director also explained in detail why any previous guidance or orders
Hess received (namely 1980s-era correspondence between Amoco and the Minerals
Management Service) that supported Hess using the Unit Average to calculate its
royalties on its federal CO2 production were not germane. Id. at 248–53. As ONRR
points out, none of the guidance OXY invokes had the force of law or was otherwise
binding on the agency. Aple. Br. at 31–37. And even if OXY was correct that
ONRR’s rejection of the Unit Average here conflicts with prior agency policy,
nothing prevented ONRR from changing its position so long as it provided a
reasonable explanation for doing so—and ONRR plainly provided a reasonable
explanation for rejecting the Unit Average.
The agency’s decision to reject the Unit Average is supported by substantial
evidence and is not arbitrary or capricious.
3. Second Regulatory Benchmark
OXY then argues that the Director misapplied the 1988 regulatory factors to
alternatively affirm the agency’s valuation under the second regulatory benchmark.
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Here, OXY’s challenge focuses on the district court’s analysis, rather than
maintaining the required focus on the Director’s analysis under the APA. Aplt. Br.
at 32–36. In affirming the Director’s alternative analysis under the 1988 regulatory
factors, the district court stated that it “[would] not second-guess the Director’s
decision in weighing the regulatory factors where the Director considered and
analyzed the relevant factors and evidence.” ROA, at 87 (emphasis added). OXY
takes issue with this statement because the district court “overlook[ed] the threshold
point that the Director had no occasion to second-guess Hess’[s] valuation in the first
instance.” Aplt. Br. at 35.
OXY’s assertion is plainly wrong under the 1988 regulations, as well as the
Unit Agreement and underlying Leases. Under the 1988 regulations, ONRR is
required to audit the valuations that lessees supply and provide reasons for rejecting a
lessee’s application of the regulatory benchmarks. 30 U.S.C. § 1711(c). Under the
Unit Agreement and Leases, their terms dictate that ONRR retains the authority to
establish a reasonable minimum valuation in accordance with the Lease valuation
factors. ROA, at 442b, 446b, 450b, 454b [Sec. 2(d)(2)]. As demonstrated, ONRR
did that here.
Id. at 242–43. Moreover, we use ordinary APA deference principles to
review the Director’s reasons for rejecting Hess’s Unit Average and approving
ONRR’s valuation under the second regulatory benchmark. We cannot reweigh the
regulatory factors if substantial evidence supports the Director’s reasoning—we
cannot even displace ONRR’s choice “between two fairly conflicting views, even
though the court would justifiably have made a different choice had the matter been
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before it de novo.” Wyo. Farm Bureau Fed’n, 199 F.3d at 1231 (internal citations
omitted).
Because the record reveals substantial evidence in support of the Director’s
analysis of the regulatory valuation factors, the Director’s decision to alternatively
affirm the agency’s valuation under the second regulatory benchmark is not arbitrary
or capricious.
B. Transportation Costs
The final issue OXY raises is whether the Director correctly determined that
Hess’s compression and dehydration costs are not deductible as a transportation
allowance because they were necessary to place Hess’s CO2 in marketable condition and
not just transport the CO2. 13 ONRR regulations allow a lessee to deduct some, but not
all, of the costs of transporting the gas from the lease to a downstream location.
30 C.F.R. § 206.156(a). Under ONRR regulations and the relevant case law, a reasonable
minimum value will not include any costs that a lessee must incur to place gas in
marketable condition. See § 206.152(i); see, e.g., Devon Energy Corp., 551 F.3d
at 1036–40; Amoco Prod. Co., 410 F.3d at 729–31; Amerada Hess Corp. v. Dep’t of the
Interior,
170 F.3d 1032, 1036–37 (10th Cir. 1999); Mesa Operating Ltd P’ship v. Dep’t
13
We note that while the Order appears to deduct “some transportation costs”
from both the “weighted average” and the Smithson formula price, the Order
explicitly disallows Hess’s reported costs associated with compression and
dehydration that are at issue here. ROA, at 253. OXY only challenges the agency’s
denial of these compression and dehydration costs as a transportation allowance and
does not discuss or challenge any other transportation costs that the Order deducted
from its valuation.
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of the Interior, 931 F.2d 318, 323–27 (5th Cir. 1991). Hess, as lessee, was responsible
for the costs to gather, compress, dehydrate, and remove any impurities from the CO2 to
meet marketable condition requirements. However, the regulations allow a lessee to
include “[s]upplemental costs for compression, dehydration, and treatment of gas . . .
only if such services [1] are required for transportation and [2] exceed the services
necessary to place production into marketable condition.” § 206.157(f)(9) (emphasis
added). So if Hess’s compression and dehydration costs (1) were required for
transportation and (2) exceeded what was necessary to compress and dehydrate the CO2
to place it in marketable condition, Hess could claim those costs as a transportation
allowance.
As the Director discussed, 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.” § 206.151. The
Director noted that “treating gas to put it in marketable condition includes gathering
(transporting gas from individual wells to a central accumulation point . . . on or near the
lease or unit), compression (increasing the pressure of gas), dehydration (removing
water), and sweetening (removing acid gases, such [sic] CO2 and hydrogen sulfide
(H2S)).” ROA, at 244–45 (citing relevant case law). In the context of Hess’s CO2
production, the Director interpreted this marketable-condition rule as requiring Hess to
treat its CO2 to conform with the pipeline requirements that served the markets into
which the CO2 was sold—the Permian Basin EOR units. Id. To meet the pressure and
quality requirements of the Permian Basin EOR units, treatment included compressing
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and dehydrating the CO2 to meet specifications regarding water vapor, hydrogen sulfide,
sulfur, oxygen, nitrogen, and hydrocarbons. Id. at 245–46 (citing the terms of the Hess
Purchase Contracts). The Director determined that “[b]ecause the ultimate use of Hess’s
CO2 production is to inject the CO2 into the EOR facility, the EOR Delivery Pipelines
represent the pressure and quality requirements for Hess’s CO2 to be in marketable
condition.” Id. at 246. Accordingly, ONRR correctly concluded that Hess could not
deduct the costs it incurred to get the CO2 to the pressure and purity specifications
required to enter the EOR delivery pipelines. Id.
The Director also acknowledged Hess’s argument that the compression costs were
necessary for transport as well but explained that “even though the compressors operate
to put the CO2 in a super critical state for transportation, they also operate to place the
CO2 in marketable condition.” Id. The Director noted that such dual-purpose costs are
deductible “only if such services are required for transportation and exceed the services
necessary to place production into marketable condition,” which Hess did not establish.
Id. at 246–47 (citing § 206.157(f)(9)) (quotations omitted).
OXY responds that CO2 is “different from other produced federal gas” and has a
“unique nature,” so “[c]ertain dehydration and compression costs are essential for CO2
transportation from the [Unit] Leases to its destination in West Texas, and therefore are
properly deductible.” Aplt. Br. at 49; Aplt. Reply Br. at 18–19. OXY contends that the
real issue is “whether transportation is the primary, not the only, reason for dehydrating
and compressing [its CO2].” Aplt. Br. at 49.
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But the Director already addressed and rejected OXY’s transportation arguments
based on the applicable regulations and case law and in the process explained why the
regulations do not embrace such a distinction. 14 ROA, at 243–47. We may reject the
Director’s interpretation and application of the marketable-condition rule to this case only
when the interpretation is “unreasonable, plainly erroneous, or inconsistent with the
regulation’s plain meaning.” Biodiversity Conservation All., 762 F.3d at 1060. The
regulations dictate that “costs for compression, dehydration, and treatment of gas” may
be deducted only to the extent “such services [1] are required for transportation and
[2] exceed the services necessary to place production into marketable condition.”
§ 206.157(f)(9). Contrary to OXY’s claims, Hess’s compression and dehydration costs
are not “unique costs related to transportation.” Aplt. Br. at 50. For CO2 to be
compatible with EOR operations, operators must remove impurities from the CO2 and
increase the gas’s pressure to transform it into a critical phase—essentially, the increased
pressure liquefies the CO2 so it can be injected at the EOR units. ROA, at 223–24. These
compression and dehydration costs are essential to bringing Hess’s CO2 to market for its
ultimate use in the EOR operations, even if they serve the dual purpose of helping
transport the gas.
14
The sources OXY cites similarly do not support its “primary purpose” theory.
Aplt. Br. at 49–53 (citing Shell Offshore Inc., 142 IBLA 71, 74 (1997) (allowing the
enlargement of a floating drilling platform to buoy a compressor and other gas
transportation equipment to be a transportation allowance under § 206.157) and Exxon
Corp., 118 IBLA 221, 240–41 (1991) (allowing dehydration of gas streams to be a
transportation allowance under § 206.157 because the dehydration in this instance
“serve[d] only one purpose: transportation”)).
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Furthermore, OXY never has demonstrated or even contended that the costs to
transport Hess’s CO2 exceeded the costs necessary to meet the minimum pressure
requirements for the EOR delivery pipelines, let alone attempted to quantify the amount
of any excess costs. And a review of the record reveals that the ultimate compression
required for transport along the pipelines to the EOR units was less than the compression
required to enter the EOR facilities. 15 As a result, OXY has not shown that the
transportation costs “exceed[ed] the services necessary to place production into
marketable condition.” § 206.157(f)(9).
OXY also asserts that the record shows ONRR allowed Hess to deduct these
compression and dehydration costs as transportation costs in the past, citing a 2002
guidance letter from ONRR. ROA, at 412–14. But as ONRR points out, this letter does
not support OXY’s claim that compression costs are deductible whenever they are
“primarily required to place the CO2 into single phase to enter a large pipeline for long
distance transport to a delivery point remote from the lease (in West Texas).” Aplt. Br.
at 52. Rather, the letter explains that a deduction is permitted only if “this compression is
solely to keep the CO2 in single-phase flow for transportation through a large diameter
pipeline to a sales point remote from the lease.” ROA, at 413 (emphasis added). And
“[i]f compression is performed to place the CO2 in marketable condition,” as OXY does
15
As OXY discusses in its briefing, Hess had to compress the CO2 to upwards of
2,500 psig to enter the EOR facilities and therefore be in marketable condition. Aplt. Br.
at 9. But Hess only had to compress the CO2 to a maximum of 2,150 psig to transport the
CO2 to the EOR facilities along the pipelines. Id.; see also ROA, at 221–22.
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not dispute is the case here, ONRR “will not allow any deductions for compression.” 16
Id.
The Director’s interpretation and application of the marketable-condition rule to
this case is not plainly erroneous or inconsistent with the applicable regulations.
IV
For the foregoing reasons, we AFFIRM.
16
OXY also argues in passing that the Director erred by relying on the regulations
to deny transportation cost deductions because the Director had valued the CO2 under the
Lease valuation factors. Aplt. Br. at 14, 16–17. However, as the district court observed,
the Director’s approach is consistent with the regulations. The regulations provide that
they should apply to the extent they are not inconsistent with the terms of the underlying
lease. 30 C.F.R. § 206.150(b). Because OXY has not pointed to any term of the Unit
Agreement or Leases inconsistent with the regulation’s marketable-condition rule, the
Director appropriately applied the regulations.
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