332 F.3d 672
D.C. Cir.
2003

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 Interi- or 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 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 ... 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 ... gas royalties ... 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)® (unprocessed gas), 206.153(b)(1)® (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 valued on the basis of downstream resales. 30 C.F.R. §§ 206.152(b)(1)® (unprocessed gas), 206.153(b)(1)® (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, ... 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.

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-92-0306-0&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 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 Texaco.... We therefore ... 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 Petroleum Corp. v. SEC, 873 F.2d 325, 340 (D.C.Cir.1989), and “the [district [c]ourt’s decision is not entitled to any particular deference,” Hennepin County v. Sullivan, 883 F.2d 85, 91 (D.C.Cir.1989). “[Notwithstanding 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, 114 S.Ct. 2381, 2386, 129 L.Ed.2d 405 (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 ... sensibly conforms to the purpose and wording of the regulations,” Martin v. Occupational Safety & Health Review Comm’n, 499 U.S. 144, 150-151, 111 S.Ct. 1171, 1176, 113 L.Ed.2d 117 (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, 65 S.Ct. 1215, 1217, 89 L.Ed. 1700 (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 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 regula tions. FOGRMA section 3(7) defines “lessee” as “any person to whom the United States, an Indian tribe, or an Indian allot-tee, 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] ... issue[d] ... leases and their affiliates,” but rather restricts the definition to “person[s] ... issue[d] ... leases.” Although the administrative record in this case does not include the actual leases, the “person to whom the United States ... 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 ... based upon the sale by the marketing affiliate,” 30 C.F.R. §§ 206.152(b)(1)(f) (unprocessed gas), 206.153(b)(1)© (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, ie., 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 non-marketing 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 commen-ters 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 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, 108 S.Ct. 1306, 1314, 99 L.Ed.2d 515 (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 nonrecognition 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 “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-corpo-rate 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.

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 in-tra-corporate transfers is too favorable to producers, she should amend the regulations through notice-and-comment rule-making, 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 ... unless otherwise provided in the lease agreement,” 30 C.F.R. §§ 206.152® (1996) (unprocessed gas), 206.153(i) (1996) (processed gas), with “marketable condition” meaning fit for “acceptance] 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.