Document ID: s3://data.kl3m.ai/documents/govinfo/USCOURTS/USCOURTS-caDC-02-05241/USCOURTS-caDC-02-05241-0/pdf.json

Parties Involved:
American Petroleum Institute
Amicus Curiae for Appellant
Fina Oil and Chemical Company
Appellant
Independent Petroleum Association of America
Amicus Curiae for Appellant
Gale A. Norton
Appellee
Petrofina Delaware, Inc.
Appellant

Document Text:

Notice: This opinion is subject to formal revision before publication in the

Federal Reporter or U.S.App.D.C. Reports. Users are requested to notify

the Clerk of any formal errors in order that corrections may be made

before the bound volumes go to press.

United States Court of Appeals

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued May 12, 2003 Decided June 27, 2003

No. 02-5241

FINA OIL AND CHEMICAL COMPANY AND

PETROFINA DELAWARE, INC.,

APPELLANTS

v.

GALE A. NORTON, SECRETARY OF THE INTERIOR,

APPELLEE

Appeal from the United States District Court

for the District of Columbia

(No. 99cv02392)

Charles D. Tetrault argued the cause for appellants. With

him on the briefs was Daniel A. Petalas.

L. Poe Leggette and Nancy L. Pell were on the brief for

amicus curiae Independent Petroleum Association of America in support of appellants.

 Bills of costs must be filed within 14 days after entry of judgment.

The court looks with disfavor upon motions to file bills of costs out

of time.

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John P. Wagner, Joshua B. Frank, and Thomas J. Eastment were on the brief for amicus curiae American Petroleum Institute in support of appellants. David T. Deal entered

an appearance.

Todd S. Aagaard, Attorney, U.S. Department of Justice,

argued the cause for appellee. With him on the brief were

Edward S. Geldermann and Ronald M. Spritzer, Attorneys.

Before: GINSBURG, Chief Judge, and ROGERS and TATEL,

Circuit Judges.

Opinion for the Court filed by Circuit Judge TATEL.

TATEL, Circuit Judge: Under federal law, firms that extract natural gas from leased federal, tribal, or offshore lands

pay the government royalties calculated as a percentage of

the value of the production they extract. This case involves a

valuation dispute concerning gas that is sold twice: first by

the producer to a gas marketing firm it controls, and then by

the controlled marketing firm to end-users. The Secretary of

the Interior valued the gas production based on the contract

price of the resale. Challenging that decision, the producer

argues that the Secretary should have valued the production

based on the lower contract price of the initial sale. Because

the applicable regulation unambiguously requires valuation

based on the initial sale, we reject the Secretary’s contrary

interpretation. Though we express no opinion on whether

the Secretary might have statutory authority to value production based on the resale price, the Secretary may not do so by

interpreting a regulation to mean the opposite of its plain

language.

I.

Through its Minerals Management Service (MMS), the

Department of the Interior issues and administers gas leases

for federal lands, Indian tribal and allotted lands, and the

Outer Continental Shelf. See Mineral Leasing Act, 30 U.S.C.

§ 181 et seq. (federal lands); Mineral Leasing Act for Acquired Lands, 30 U.S.C. § 351 et seq. (acquired federal lands);

25 U.S.C. §§ 396, 396a–396g (Indian tribal and allotted

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lands); Outer Continental Shelf Lands Act, 43 U.S.C. § 1331

et seq. (Outer Continental Shelf). See generally Indep. Petroleum Ass’n v. Babbitt, 92 F.3d 1248, 1251–52 (D.C. Cir. 1996).

Under such leases, private companies sell gas production

directly and then compensate the government with royalties

calculated as a percentage of the ‘‘value of the production’’

removed or sold from the leased lands. 30 U.S.C. § 226(b)

(federal lands); 43 U.S.C. § 1337(a)(1) (Outer Continental

Shelf); 25 C.F.R. §§ 211.41(b) & 212.41(b) (Indian tribal and

allotted lands). Concerned that ‘‘the system of accounting

with respect to royalties and other payments due and owing

on TTT gas produced from [federal, tribal, and offshore] lease

sites is archaic and inadequate,’’ 30 U.S.C. § 1701(a)(2), Congress enacted the Federal Oil and Gas Royalty Management

Act (FOGRMA), 30 U.S.C. § 1701 et seq. (1982), which directed the Secretary to ‘‘establish a comprehensive inspection,

collection and fiscal and production accounting and auditing

system to provide the capability to accurately determine TTT

gas royalties TTT owed, and to collect and account for such

amounts in a timely manner,’’ 30 U.S.C. § 1711(a).

Pursuant to FOGRMA and the leasing statutes, the MMS

promulgated a regulation establishing methods for determining the ‘‘value of the production’’ for royalty calculation

purposes. See Revision of Gas Royalty Valuation Regulations and Related Topics, 53 Fed. Reg. 1230 (Jan. 15, 1988)

(codified at 30 C.F.R. §§ 206.152 (unprocessed gas), 206.153

(processed gas)). The regulation establishes three different

valuation methodologies, depending on the particular entity

to whom producers first sell the gas. Gas sold directly to

non-affiliated purchasers under ordinary ‘‘arm’s-length contract[s]’’ is valued on the basis of ‘‘gross proceeds accruing to

the lessee’’—a defined term meaning total direct and indirect

consideration under the contract. 30 C.F.R.

§§ 206.152(b)(1)(i) (unprocessed gas), 206.153(b)(1)(i) (processed gas), 206.151 (defining ‘‘arm’s length contract’’ and

‘‘gross proceeds’’). Gas sold to so-called marketing affiliates—entities that purchase gas exclusively from producers

that own or control them—and subsequently resold by the

marketing affiliates pursuant to arm’s-length contracts is

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valued on the basis of downstream resales. 30 C.F.R.

§§ 206.152(b)(1)(i) (unprocessed gas), 206.153(b)(1)(i) (processed gas), 206.151 (defining ‘‘marketing affiliate’’). Gas

sold to owned or controlled affiliated entities that, because

they purchase at least some gas from sources other than

their owning or controlling producer, are not ‘‘marketing

affiliates’’ is valued on the basis of the first applicable of

three benchmarks. 30 C.F.R. §§ 206.152(c) (unprocessed

gas), 206.153(c) (processed gas). The first benchmark values

gas based on ‘‘gross proceeds accruing to the lessee pursuant

to a sale under its non-arm’s-length contract, TTT provided

that those gross proceeds are equivalent to the gross proceeds derived from [comparable sales in the same field or

area].’’ 30 C.F.R. §§ 206.152(c)(1) (unprocessed gas),

206.153(c)(1) (processed gas). The second benchmark values

gas based on ‘‘information relevant in valuing like-quality

gas,’’ including ‘‘other reliable public sources of price or

market information.’’ 30 C.F.R. §§ 206.152(c)(2) (unprocessed gas), 206.153(c)(2) (processed gas). The third, which

values gas based on another proxy for market price under an

arm’s-length contract, is irrelevant to this case. 30 C.F.R.

§§ 206.152(c)(3) (unprocessed gas), 206.153(c)(3) (processed

gas). Finally, and central to this case, the regulation contains a catch-all: ‘‘Notwithstanding any other provision of

this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds

accruing to the lessee for lease production.’’ 30 C.F.R.

§§ 206.152(h) (unprocessed gas), 206.153(h) (processed gas).

Appellants Fina Oil and Chemical Company and Petrofina

Delaware, Inc. are natural gas producers holding onshore and

offshore federal leases. (Like the parties, we shall call

appellants ‘‘Fina.’’) Fina Natural Gas Company (FNGC) is a

natural gas marketer that purchases gas from producers for

resale to downstream end-users. Though controlled by Fina,

FNGC is not a ‘‘marketing affiliate’’ because it purchases gas

from both Fina and other gas producers. Fina therefore paid

royalties based on its contract price with FNGC—a price

which, according to Fina, complies with the first benchmark

or, if the first benchmark is inapplicable, with the second.

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In 1993, the MMS issued an order rejecting Fina’s use of

the benchmarks, requiring Fina instead to base its royalty

valuation on the higher prices that FNGC receives from

subsequent downstream arm’s-length sales. Fina appealed to

the Interior Board of Land Appeals, but while that appeal

was pending, the Board decided Seagull Energy Corp., 148

I.B.L.A. 300 (May 6, 1999), which reversed an MMS order

substantially similar to the order in Fina’s case and squarely

rejected the MMS’s position that gas sold to non-marketing

affiliates and later resold to end-users must be valued based

upon the resale price.

Seagull proved short-lived. Two weeks after it was issued,

the Acting Assistant Secretary for Land and Minerals Management, with the Secretary of the Interior’s concurrence,

expressly overruled Seagull in a decision called Texaco Exploration & Production, Inc., Docket No. MMS–92–0306–

O&G (May 18, 1999). Though Texaco involved the valuation

of oil, not gas, it presented the same legal issue we face here

because the MMS’s oil valuation and gas valuation regulations

are identical for all relevant purposes, see Revision of Oil

Product Valuation Regulations and Related Topics, 53 Fed.

Reg. 1184 (Jan. 15, 1988) (codified at 30 C.F.R. §§ 202.101–

.102), and because the oil was sold by a producer (like Fina)

to a non-marketing affiliate (like FNGC). Holding the benchmarks inapplicable in valuing oil production resold at a profit

by a non-marketing affiliate, Texaco expressly rejected Seagull’s reasoning on two grounds. First, Texaco noted that

the gross proceeds provision requires all valuations to equal

at a minimum the ‘‘gross proceeds accruing to the lessee,’’ a

term the decision interpreted as referring to the total consideration received by the corporate family to which the producer and non-marketing affiliate belong. Because the benchmarks measure only what the producer receives through

intra-corporate transfers, not the total consideration the corporate family receives from resale, Texaco reasoned that the

benchmarks yield valuations less than ‘‘gross proceeds accruing to the lessee’’ whenever a non-marketing affiliate resells

gas for more than it originally paid its controlling producer.

Thus, Texaco found that in such instances the gross proceeds

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provision supersedes the benchmarks, requiring the producer

to calculate value based on its non-marketing affiliate’s resale

proceeds. Second, finding that oil and gas lessees have an

implied duty to include in production valuations any increase

in value resulting from marketing activities, Texaco concluded, alternatively, that a lessee may not base valuations on

sales to a non-marketing affiliate that later turns around and

performs marketing activities. Texaco at 12–22.

Because the Assistant Secretary issued Texaco under her

discretionary authority to step into the MMS director’s shoes

and directly hear appeals from MMS orders, Texaco binds

the Board. See Texaco at 27; Blue Star, Inc., 41 I.B.L.A. 333

(1979) (finding Board bound by decision made by Assistant

Secretary standing in the shoes of a subdepartment of the

Department of the Interior); Marathon Oil Co., 108 I.B.L.A.

177 (1989) (same). Accordingly, the Board summarily denied

Fina’s appeal, concluding that ‘‘[t]he arguments raised by

appellants with respect to the value of production for royalty

purposes have all been addressed in TexacoTTTT We therefore TTT adopt the analysis and rational [sic] contained therein to affirm MMS.’’ Fina Oil & Chem. Co., 149 I.B.L.A. 168,

186 (June 11, 1999).

Fina filed suit in the United States District Court for the

District of Columbia challenging the Board’s decision under

the Administrative Procedure Act, 5 U.S.C. § 551 et seq. On

cross motions for summary judgment, the district court ruled

for the Secretary. Reaching only Texaco’s second rationale,

the district court found it ‘‘neither arbitrary nor capricious for

the [Secretary] to conclude that Fina has some implied duty

to market the gas it produces.’’ Fina Oil & Chem. Co. v.

Norton, 209 F. Supp. 2d 246, 253 (D.D.C. 2002). Fina now

appeals.

II.

Although Fina’s challenge to the Secretary’s interpretation

of her own regulation comes to us on appeal from the district

court, because we face a purely legal question, ‘‘our task [is]

precisely the same as the district court’s,’’ Occidental PetroleUSCA Case #02-5241 Document #756560 Filed: 06/27/2003 Page 6 of 12
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um Corp. v. SEC, 873 F.2d 325, 340 (D.C. Cir. 1989), and ‘‘the

[d]istrict [c]ourt’s decision is not entitled to any particular

deference,’’ Hennepin County v. Sullivan, 883 F.2d 85, 91

(D.C. Cir. 1989). ‘‘[N]otwithstanding the intervening step,’’

we thus ‘‘proceed as if the [Board’s] decision had been

appealed to this court directly.’’ Dr. Pepper/Seven–Up Cos.

v. FTC, 991 F.2d 859, 862 (D.C. Cir. 1993).

In reviewing the Board’s application of its gas valuation

regulations to Fina’s operations and the Secretary’s reasoning

in Texaco that the Board adopted by reference, ‘‘[w]e must

give substantial deference to an agency’s interpretation of its

own regulations.’’ Thomas Jefferson Univ. v. Shalala, 512

U.S. 504, 512 (1994). Courts, the Supreme Court has explained, lack authority to ‘‘decide which among several competing interpretations [of an agency’s own regulation] best

serves the regulatory purpose,’’ id., and instead must ‘‘give

effect to the agency’s interpretation so long as it TTT sensibly

conforms to the purpose and wording of the regulations,’’

Martin v. Occupational Safety & Health Review Comm’n,

499 U.S. 144, 150–151 (1991) (internal quotation marks and

citations omitted). But to prevent agencies from circumventing the notice-and-comment process by rewriting regulations

under the guise of interpreting them, we will reject an agency

interpretation that is ‘‘plainly erroneous or inconsistent with

the regulation.’’ Bowles v. Seminole Rock & Sand Co., 325

U.S. 410, 414 (1945); cf. Darrell Andrews Trucking, Inc. v.

Fed. Motor Carrier Safety Admin., 296 F.3d 1120, 1125 (D.C.

Cir. 2002) (holding that agencies may not abandon ‘‘prior,

definitive’’ interpretations of their own regulations without

first engaging in notice-and-comment rulemaking).

Fina argues that the benchmarks should control this case

because (1) the Secretary’s position—that valuation must

equal or exceed the total consideration accruing to the corporate family as a whole—misinterprets the gross proceeds rule

and (2) Fina fully discharged its duty to market its production

at no cost to the government by selling to FNGC. Defending

both of Texaco’s rationales, the Secretary argues that the

benchmarks are inapplicable because (1) the catch-all gross

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proceeds provision requires valuation based on total consideration accruing to the corporate family as a whole and (2)

Fina’s implied duty to market its production at no cost to the

government requires valuation based on FNGC’s sales, not

Fina’s.

Beginning with the gross proceeds provision, we of course

agree with the Secretary that because the provision applies

‘‘[n]otwithstanding any other provision of this section,’’ it

trumps any methodology, including the benchmarks, that

yields valuations ‘‘less than the gross proceeds accruing to the

lessee for lease production.’’ 30 C.F.R. §§ 206.152(h) (unprocessed gas), 206.153(h) (processed gas), 206.102(h) (1999) (oil).

At this point, however, our agreement with the Secretary

ends. As we shall show, the underlying statute’s definition of

‘‘lessee,’’ the regulation’s language and structure, and the

agency’s own pronouncements at the time of the regulation’s

promulgation all demonstrate that ‘‘gross proceeds accruing

to the lessee’’ refers only to proceeds accruing to Fina, not to

the entire corporate family of which Fina is a member.

Reading the Board’s decision and the Texaco decision that

it incorporates by reference, one would never know that the

term ‘‘lessee’’—whose meaning is critical to this case—is

defined in both the underlying statute and the MMS’s own

regulations. FOGRMA section 3(7) defines ‘‘lessee’’ as ‘‘any

person to whom the United States, an Indian tribe, or an

Indian allottee, issues a lease, or any person who has been

assigned an obligation to make royalty or other payments

required by the lease.’’ Pub. L. No. 97–451 § 3(7), 96 Stat.

2447, 2449 (amended in 1996, after the events at issue in this

case, to read ‘‘any person to whom the United States issues

an oil and gas lease or any person to whom operating rights

in a lease have been assigned’’ and codified at 30 U.S.C.

§ 1702(7)). The MMS incorporated this definition word for

word in both its oil and gas valuation regulations. 30 C.F.R.

§§ 206.101 (1988) (oil), 206.151 (1988) (gas). The definition

could hardly be clearer. It defines ‘‘lessees’’ not as ‘‘person[s] TTT issue[d] TTT leases and their affiliates,’’ but rather

restricts the definition to ‘‘person[s] TTT issue[d] TTT leases.’’

Although the administrative record in this case does not

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include the actual leases, the ‘‘person to whom the United

States TTT issue[d] a lease’’ is clearly Fina. Not only does

the Secretary allege no formal relationship between the United States and FNGC, but in its very first paragraph, the

Board’s decision identifies Fina as the ‘‘lessee[ ]/appellant[ ]’’

and FNGC simply as Fina’s ‘‘affiliate.’’ Fina, 149 I.B.L.A. at

169.

The regulation’s overall structure and statements of agency

intent at the time of promulgation provide additional reasons

why the Secretary’s interpretation of the gross proceeds

provision is quite wrong. The marketing affiliate provision,

which states that ‘‘gas which is sold or otherwise transferred

to the lessee’s marketing affiliate and then sold by the

marketing affiliate pursuant to an arm’s-length contract shall

be valued TTT based upon the sale by the marketing affiliate,’’

30 C.F.R. §§ 206.152(b)(1)(i) (unprocessed gas),

206.153(b)(1)(i) (processed gas), shows that the regulation’s

authors knew just how to require valuations based on downstream resales when they intended such methodology. Moreover, not only did they limit this methodology to marketing

affiliates—which FNGC is not—but the regulation contains

provisions that expressly deal with valuation of production

sold to non-marketing affiliates, i.e., the benchmarks, which

provide for valuation based on non-arm’s-length transactions,

such as intra-corporate transfers.

Removing any doubt about the treatment of sales to nonmarketing affiliates, the regulation’s preamble makes plain

that the decision to restrict valuation based on downstream

sales to marketing affiliates was intentional. In response to

commenters who proposed expanding the marketing affiliate

rule to encompass affiliates who acquire any gas from their

owners or controllers, rather than affiliates who acquire gas

only from their owners or controllers, the agency stated that:

‘‘The MMS is retaining the term ‘only.’ If the affiliate of the

lessee also purchases gas from other sources, then that

affiliate presumably will have comparable arm’s-length contracts with the other parties which should demonstrate the

acceptability of the gross proceeds accruing to the lessee

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from its affiliate.’’ Revision of Gas Royalty Valuation Regulations, 53 Fed. Reg. at 1243.

In sum, the overall import of the regulation’s tripartite

structure and ‘‘other indications of the [agency’s] intent at the

time of the regulation’s promulgation,’’ Gardebring v. Jenkins, 485 U.S. 415, 430 (1988), is crystal clear. Gas sold

directly to unaffiliated entities is valued at the contract price,

since that price reliably indicates objective value. In contrast, gas sold to marketing affiliates is valued not on the

basis of the initial sale—obviously an unreliable indicator of

objective value—but rather on the basis of the price at which

it ultimately leaves the corporate family. But the agency

expressly restricted non-recognition of intra-corporate sales

to situations where no directly comparable arm’s-length sales

exist. Accordingly, gas sold to non-marketing affiliates—

where objective value can be reliably approximated through

comparable arm’s-length sales—is valued through the benchmarks at the initial sales price and not the subsequent resale

price.

As against this clear policy choice enshrined in the regulation, the Secretary takes the exact opposite position. Declining to recognize intra-corporate transfers of gas from Fina to

FNGC, even though benchmark comparisons exist, the Secretary argues that Fina should calculate value as if FNGC were

a marketing affiliate, i.e., on the basis of downstream resales.

At oral argument, we asked counsel for the Secretary to

explain why this interpretation did not read the benchmarks

out of the statute—that is, if non-marketing affiliates are

treated just like marketing affiliates, what purpose do the

benchmarks serve? Although it is true, as counsel responded, that the benchmarks would still apply to non-marketing

affiliates selling gas downstream for less than the price at

which they bought it, Oral Arg. Tr. 15:6–16, nothing in either

the regulation or its preamble suggests that the benchmarks

cover only the limited subset of non-marketing affiliates who

fail to turn a profit.

Moreover, the Secretary’s interpretation would ripple

through other parts of the regulation that use the term

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‘‘lessee,’’ creating several linguistic absurdities. For instance,

the first benchmark for valuing gas sold to non-marketing

affiliates is defined as ‘‘gross proceeds accruing to the lessee

pursuant to a sale under its non-arm’s-length contract.’’ 30

C.F.R. §§ 206.152(c)(1) (unprocessed gas), 206.153(c)(1) (processed gas). Under the Secretary’s interpretation of ‘‘lessee,’’

this phrase would make no sense. If ‘‘gross proceeds accruing to the lessee’’ refers to total proceeds accruing to corporate families, then as a logical matter no gross proceeds can

accrue to lessees pursuant to purely intra-corporate ‘‘nonarm’s-length contract[s].’’

The regulation’s definition of ‘‘marketing affiliate’’—‘‘an

affiliate of the lessee whose function is to acquire only the

lessee’s production and to market that production,’’ 30 C.F.R.

§ 206.151—illustrates the same point. If affiliates are lessees

then it makes no sense to talk about an ‘‘affiliate of the

lessee’’ nor of affiliates acquiring lessees’ production.

In still a third example, the preamble’s explanation of the

marketing affiliate rule refers to the ‘‘gross proceeds accruing

to the lessee from its affiliate.’’ Revision of Gas Royalty

Valuation Regulations, 53 Fed. Reg. at 1243 (emphasis added). In addition to implying that lessees and affiliates are

distinct entities, this phrase completely contradicts the Secretary’s position that producers like Fina cannot accrue gross

proceeds from their affiliates, such as FNGC.

In Texaco, the Secretary warned that valuing production

based on intra-corporate sales ‘‘allows any lessee to avoid the

gross proceeds requirement by the simple and facile device of

creating a wholly-owned subsidiary and then first transferring the production to the affiliate, for a price the lessee

determines unilaterally, before selling the production at arm’s

length at a higher price.’’ Texaco at 7. We disagree. Even

Fina’s position would not allow it to set prices ‘‘unilaterally,’’

for the benchmarks require Fina to base value on the prices

that its affiliate, FNGC, pays other producers. In other

words, Fina must pay royalties based on the actual market

value of the gas at the time Fina transfers the gas to its

affiliate.

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Although the Secretary does not expressly say so, her

primary concern seems to be that valuing the gas based on

the initial sale would allow Fina and other lessees to pay

royalties on gas before its value increases through the transportation and marketing services provided by affiliates like

FNGC. But this is precisely what the regulation permits. If

the Secretary now believes—as Texaco and her position here

indicate—that recognizing intra-corporate transfers is too

favorable to producers, she should amend the regulations

through notice-and-comment rulemaking, not under the guise

of interpretation.

The Secretary’s second ground for rejecting application of

the benchmarks requires little discussion. The regulation

states that ‘‘lessee[s] [are] required to place gas in marketable condition at no cost to the Federal Government TTT

unless otherwise provided in the lease agreement,’’ 30 C.F.R.

§§ 206.152(i) (1996) (unprocessed gas), 206.153(i) (1996) (processed gas), with ‘‘marketable condition’’ meaning fit for

‘‘accept[ance] by a purchaser under a sales contract typical

for the field or area,’’ id. § 206.151. Acknowledging that we

have previously interpreted this provision to mean that only

producers who market gas downstream, not producers who

‘‘opt to sell at the leasehold,’’ must pay royalties based on the

increase in gas value associated with marketing expenditures,

Indep. Petroleum Ass’n v. DeWitt, 279 F.3d 1036, 1041 (D.C.

Cir. 2002), the Secretary argues that ‘‘Fina did market its

production downstream, through its affiliate FNGC,’’ Appellee’s Br. at 46. This argument, however, differs not at all

from the Secretary’s basic position against recognizing intracorporate sales for valuation purposes—a position that, as we

have just explained, conflicts with the regulation’s plain language.

The judgment of the district court is reversed.

So ordered.

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