
    410 F.3d 722
    AMOCO PRODUCTION COMPANY, Appellant v. Rebecca W. WATSON, Assistant Secretary for Land and Mineral Management, et al., Appellees
    Nos. 04-5006, 04-5007.
    United States Court of Appeals, District of Columbia Circuit.
    Argued Feb. 14, 2005.
    Decided June 10, 2005.
    
      Steven R. Hunsicker argued the cause for appellants. With him on the briefs was Melissa E. Maxwell.
    Craig L. Stahl was on the brief for amicus curiae Burlington Resources, Inc. in support of appellant. John T. Boese and Laura B. Rowe entered appearances.
    John A. Bryson, Attorney, U.S. Department of Justice, argued the cause and filed the brief for appellees. Ellen J. Durkee, Attorney, U.S. Department of Justice, entered an appearance.
    Patricia A Madrid, Attorney General, Attorney General’s Office of the State of New Mexico, Christopher D. Coppin, Assistant Attorney General, Thomas H. Shipps, Ken Salazar, Attorney General, Attorney General’s Office of the State of Colorado, Alan J. Gilbert, Solicitor General, Lee Ellen Helfrich, Martin Lobel, Jill Elise Grant, Harry R. Sachse, and James E. Glaze were on the brief for amici curiae in support of appellees.
    Before: EDWARDS, SENTELLE, and ROBERTS, Circuit Judges.
   Opinion for the Court filed by

Circuit Judge ROBERTS.

ROBERTS, Circuit Judge.

The San Juan Basin covers 7500 square miles in northwest New Mexico and southwest Colorado. Since the end of World War II, it has been a prolific source of natural gas, connected by pipeline to southern California and literally helping to fuel the dramatic growth of that region. Beginning in the 1980s, large-scale extraction of the variety of natural gas known as coalbed methane began to supplement the supply of conventional gas from the region. Coalbed methane contains upwards often percent carbon dioxide, which is largely absent from conventional natural gas. Because carbon dioxide does not produce energy, mainline natural gas pipelines will not accept gas with a carbon dioxide component of more than two to three percent of volume. A high carbon dioxide content does not render the natural gas useless for consumers, but if producers in the San Juan Basin want to sell their gas to markets beyond that sparsely populated region, they must use the mainline and meet its more stringent carbon dioxide standard.

The federal government is a large landowner in the San Juan Basin and, like many other owners of property rich in natural gas, it leases rights to extract the gas in exchange for a percentage of the proceeds. Unlike the case with other landowners, however, the relationship between the government and those who extract gas from the government’s land is regulated pursuant to an elaborate array of statutes and rules. The present case involves several disputes between the government and gas producers over how the need to remove the excess carbon dioxide from coalbed methane, to make it palatable to the mainline pipelines, affects the royalty payment the producers owe the government under those statutes and regulations. For the reasons that follow, we affirm the district court’s decision and uphold the government’s determination that the producers owe additional royalties.

I. Background

Statutory and Regulatory Framework. The Department of the Interior (DOI), through its Minerals Management Service (MMS), issues and administers leases authorizing the extraction of natural gas from government land. The Mineral Leasing Act (MLA), 30 U.S.C. §§ 181 et seq. (2000), requires producer-lessees to pay the government-lessor “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.” Id. § 226(b)(1)(a). To ensure the government gets its due in royalties, the Secretary of the Interior is directed by statute to establish a comprehensive inspection, auditing, and collection system. See id. § 1711.

In 1988, pursuant to these statutes, MMS “amended and clarified” the rules “governing valuation of gas for royalty computation purposes.” Revision of Gas Royalty Valuation Regulations and Related Topics, 53 Fed.Reg. 1230 (Jan. 15, 1988). Under these new regulations, MMS specified that the “value of the production” referred to in 30 U.S.C. § 226(b)(1)(A) must be no less than “the gross proceeds accruing to the lessee for lease production,” minus certain allowable deductions. 30 C.F.R. § 206.152(h) (1988). A factor in calculating these “gross proceeds” is a longstanding interpretation of the MLA that obligates lessees to put the gas they extract in “marketable condition at no cost to” the federal lessor. Id. § 206.152(i); see California Co. v. Udall, 296 F.2d 384, 387-88 (D.C.Cir.1961) (upholding marketable condition requirement). Under the 1988 regulations, lease products are considered in marketable condition if they “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.” 30 C.F.R. § 206.151. If a lessee sells “unmarketable” gas at a lower cost, the gross proceeds for purposes of royalty calculation must be “increased to the extent that gross proceeds have been reduced because the purchaser, or any other person, is providing certain services” to place the gas in marketable condition. Id. § 206.152®. To take a simple example, if it costs $20 to put gas in marketable condition by removing impurities, and the purified gas is sold for $100, “gross proceeds” for purposes of royalty calculations is $100, regardless of whether the producer removes the impurities and sells the gas for $100, or instead sells the gas for $80 to a purchaser who then removes the impurities.

The regulations allow lessees to deduct from gross proceeds costs directly related to transporting gas from the wellhead for sale at markets remote from the lease. See id. § 206.157(a)-(b). The government’s generosity with respect to this deduction, however, goes only so far — absent approval from MMS, a lessee is not allowed to deduct the costs of transporting non-royalty bearing products. See id. § 206.157(a)(2)(i), (b)(3)®. In other words, to the extent the government is not going to share in the proceeds of the producers’ distant sale, because some of the product is non-royalty bearing, the government does not in effect share in the cost of transporting that portion of the product by having that cost deducted from “gross proceeds.” There is an exception to this logic: a portion of the product may fall into a category known as “waste products which have no value.” Id. § 206.157(a)(2)®, (b)(3)®. Although it may at first seem counterintuitive, the government allows a deduction for the cost of transporting such waste products, because such transport is considered part of the cost of transporting the royalty-bearing product with which the waste products are associated.

Facts and Rulings Below. Producers Amoco Production Company (Amoco) and Atlantic Richfield Company and Vastar Resources, Inc. (ARCO/Vastar) produce coalbed methane on public land in the San Juan Basin pursuant to leases with the federal government. To make the coalbed methane suitable for transportation over mainline pipelines, the producers arranged for the removal of excess carbon dioxide from most of the gas they extracted. Between 1989 and 1996, the producers sold untreated gas at the wellhead to purchasers who would pipe the gas to treatment centers, remove the excess carbon dioxide, and then put the treated gas on the mainline system for transport and sale to end-users throughout the country. The producers’ sales arrangements differed; Amoco would sell untreated gas primarily to a wholly-owned trading subsidiary and ARCO/Vastar would contract arms-length sales with unaffiliated purchasers. Nevertheless, the economics of the transactions were the same, with the price of untreated gas at the wellhead reflecting the fact that the purchaser would have to transport the gas to treatment plants and remove the excess carbon dioxide before sending the gas into the mainline.

On April 22, 1996, MMS issued a letter to lease operators and royalty payors in the San Juan Basin laying out the Service’s “guidelines” for calculating royalties on coalbed methane. Payor Letter, at 1. The Payor Letter informed the producers that removing excess carbon dioxide was considered a cost of placing the gas in marketable condition. Consequently, producers who removed the gas themselves could not deduct the cost of doing so from gross proceeds, and those selling untreated gas at a lower price nevertheless needed to add back to gross proceeds the cost of removal services performed by the purchaser. See id. at 1-2. The letter also addressed transportation allowances, specifying that producers could deduct the costs of piping the methane and the allowable two to three percent portion of carbon dioxide to the treatment center, but not the cost of transporting the excess carbon dioxide to be removed at the center. In the government’s view, that excess constituted a non-royalty bearing product under the regulations. See id. at 2-3.

On the heels of the Payor Letter, MMS issued separate orders finding Amoco and ARCO/Vastar deficient in their royalty payments for the period between 1989 and 1996. This shortfall stemmed from the producers’ accounting for sales of raw coalbed methane that was later treated and marketed on the mainline by its purchasers. In calculating gross proceeds, the producers did not add back the costs incurred by the purchasers in moving the excess carbon dioxide to the treatment plant and removing it once there. Instead, they calculated gross proceeds the same way they did for sales of coalbed methane used in untreated form by local purchasers. MMS thus concluded that Amoco and ARCO/Vastar owed the government additional royalties totaling $4,117,607 and $782,873, respectively. The producers did not have to add back to gross proceeds the cost of transporting royalty-bearing methane and the allowable three percent carbon dioxide “waste product” — because this cost was deductible in the government’s view— and the orders did not assess any additional royalties on sales of gas consumed without treatment.

In separate challenges to these orders before the Assistant Secretary for Land and Minerals Management, the producers argued that untreated gas at the wellhead was already in marketable condition — after all, they sold a fair amount of it in that form, and it was used without treatment— so there was no reason to augment their gross proceeds for royalty calculation purposes. They also argued that the cost of piping the excess carbon dioxide to the treatment plant should be viewed as a deductible transportation cost, not a cost of putting the gas in marketable condition. In the alternative, the producers contended that, under the transportation regulations, the excess carbon dioxide piped to the treatment plants should be regarded as a “waste product.” The Assistant Secretary rejected these challenges and also concluded — contrary to the producers’ contentions — that the Payor Letter was not a rule, and so was not subject to the Administrative Procedure Act’s notice and comment requirement. See 5 U.S.C. § 553. The Assistant Secretary also rejected the producers’ argument that collection of the royalties was barred by the six-year statute of limitations for government actions for money damages found in 28 U.S.C. § 2415.

In the District Court for the District of Columbia, the producers sought a declaratory judgment and injunction against enforcement of the MMS orders. On cross-motions for summary judgment, the district court ruled for the government. See Amoco Production Co. v. Baca, 300 F.Supp.2d 1 (D.D.C.2003). Amoco and ARCO/Vastar appeal.

II.

We review the district court decision de novo, Fina Oil & Chem. Co. v. Norton, 332 F.3d 672, 675-76 (D.C.Cir.2003), and will reverse the Assistant Secretary’s rulings only if they are “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law,” or if they are “in excess of statutory jurisdiction, authority, or limitations, or short of statutory right.” 5 U.S.C. § 706(2)(A), (C); Gerber v. Norton, 294 F.3d 173, 178 (D.C.Cir.2002).

A. We first turn to the producers’ argument that the Assistant Secretary’s application of the marketable condition rule violates the MLA. The Assistant Secretary concluded that “the value for royalty purposes must be determined by adding to the gross proceeds received from the wellhead purchaser the cost of treating the gas ... to the level required to place the gas in marketable condition.” MMS Decision of Sept. 12, 2000 (Amoco Decision) at 10 [J.A. 11]; MMS Decision of Mar. 24, 2000 (ARCO/Vastar Decision) at 6. The producers contend this conclusion cannot be squared with the statutory provision requiring producers to pay royalties based on the “amount or value of the production removed or sold from the lease.” 30 U.S.C. § 226(b)(1)(A) (emphasis added). The producers read the underscored phrase as requiring that the physical leasehold be treated as the relevant geographic market, precluding calculation of royalties based on gross proceeds derived from sales remote from the wellhead.

We review the agency’s interpretation of the MLA, a statute DOI administers, within the framework of Chevron, U.S.A., Inc. v. Natural Res. Def. Council, Inc., 467 U.S. 837, 104 S.Ct. 2778, 81 L.Ed.2d 694 (1984). See Indep. Petroleum Ass’n of Am. v. DeWitt, 279 F.3d 1036, 1039-40 (D.C.Cir.2002) (“IPAA ”). Under the first step of Chevron, we inquire whether Congress has spoken directly to the question at issue. 487 U.S. at 842, 108 S.Ct. 2687. If so, we give effect to that clearly expressed intent. If instead the statute is “silent or ambiguous with respect to the specific issue,” we defer to the agency interpretation, so long as it is reasonable. Id. at 842-43, 108 S.Ct. 2687.

Although the producers present a textually plausible reading of section 226, theirs is not the only one available. The phrase “from the lease” is sufficiently broad to be read as referring simply to the origin of the gas. Gas that is “from the lease” and that is marketed at a remote location can readily be described as gas “removed or sold from the lease.” The producers read the statute as if it referred to gas “sold at the lease,” but that is not the case. They direct us to no precedent limiting marketable condition to their narrowing construction. Although they observe that this court in California Co. applied the marketable condition rule to sales of treated gas near the wellhead, that is of little help to them; all the gas at issue there “was conditioned by the seller and delivered to the purchaser within a short distance of the wells,” 296 F.2d at 387, so the question presented here did not arise.

The producers’ reliance on our more recent decision in IPAA is also misplaced. They direct to us to a portion of the opinion observing that DOI “abide[s] by the statutory mandate to base royalty on the ‘value of the production removed or sold from the lease,’ ” 279 F.3d at 1037 (quoting 30 U.S.C. § 226(b)(1)(A)), but the cited dictum does not even interpret “from the lease,” let alone do so authoritatively. If anything, IPAA was skeptical of the producers’ “almost metaphysical” proposition “that the sale of ‘marketable condition’ gas at the leasehold represented] a baseline” beyond which the government had to share any costs incurred further down the line. Id. at 1041.

Because the Assistant Secretary has not interpreted the statute in a manner contrary to clear congressional intent, the next step is to ask whether her construction is a reasonable one. See Chevron, 467 U.S. at 843, 104 S.Ct. 2778. The producers do not, however, appear to marshal a step two argument. Consequently, we have no basis for finding the Assistant Secretary’s interpretation unreasonable. See Consumer Elec. Ass’n v. FCC, 347 F.3d 291, 299 (D.C.Cir.2003).

B. The producers also contend that the Assistant Secretary acted arbitrarily and capriciously by misinterpreting the MLA regulations and departing from agency precedent. Although we will not allow an agency to “rewrit[e] regulations under the guise of interpreting them,” Fina Oil, 332 F.3d at 676, we nevertheless owe “substantial deference to an agency’s interpretation of its own regulations,” giving that interpretation “controlling weight unless it is plainly erroneous or inconsistent with the regulation,” Thomas Jefferson Univ. v. Shalala, 512 U.S. 504, 512, 114 S.Ct. 2381, 129 L.Ed.2d 405 (1994) (internal quotation marks omitted). Such deference is particularly appropriate in the context of “ ‘a complex and highly technical regulatory program,’ in which the identification and classification of relevant ‘criteria necessarily require significant expertise and entail the exercise of judgment grounded in policy concerns.’ ” Id. (quoting Pauley v. BethEnergy Mines, Inc., 501 U.S. 680, 697, 111 S.Ct. 2524, 115 L.Ed.2d 604 (1991)).

The producers argue that the DOI regulation defining gas in “marketable condition” as gas acceptable to “a purchaser under a sales contract typical for the field or area,” 30 C.F.R. § 206.151, requires MMS to consider untreated gas sold at the wellhead to be in marketable condition, notwithstanding any later off-lease treatment. The Assistant Secretary concluded, however, that because the “dominant market for gas from the area is for gas that is utilized in distant markets with a much lower C02 content,” sales contracts for treated gas were typical for the area, while those for untreated gas were not. Amoco Decision at 7; see also ARCO/Vastar Decision at 5. Although the producers concede that most of the gas purchased at their leaseholds is treated for use in downstream markets, they argue that the Assistant Secretary’s “dominant end-use” rationale is irreconcilable with the text of section 206.151 of the regulations, which frames typicality in terms of a given “field or area.”

We are not persuaded, however, that the regulations require MMS to understand typical sales contracts — and thus marketable condition — as relating to transactions at the leasehold or immediately nearby. As an initial matter, it is not even clear that “field or area” — the textual hook for the producers’ interpretation — refers only to leasehold land. The regulations define “area” as “a geographic region at least as large as the defined limits of [a] gas field, in which ... gas lease products have similar quality, economic, and legal characteristics,” and define “field” as “a geographic region situated over one or more subsurface ... gas reservoirs encompassing at least the outer-most boundaries of all ... gas accumulations.” 30 C.F.R. § 206.151 (emphases added). Because these terms do not foreclose the possibility of defining a region beyond the geographical limits of a leasehold, we are hesitant to conclude that the Assistant Secretary’s interpretation failed to “sensibly conform[] to the purpose and wording of the regulations.” Martin v. Occupational Safety and Health Review Comm’n, 499 U.S. 144, 151, 111 S.Ct. 1171, 113 L.Ed.2d 117 (1991) (internal quotation marks omitted).

The producers’ construction also does not square with the regulatory scheme as a whole. The regulation stipulating that producers are to place gas in marketable condition at no cost to the government does not contain a geographic limit. See 30 C.F.R. § 206.152(i). More importantly, regulations governing transportation allowances obviously assume that valuation of gas “at a point (e.g., sales point or point of value determination) off the lease” is permissible. Id. § 206.156(a). The Assistant Secretary’s approach to the marketable condition rule is entirely consistent with this regulatory scheme and the basic principle that the MLA contemplates a meaningful distinction between marketing and merely selling gas. See California Co., 296 F.2d at 388.

The Assistant Secretary’s approach to marketable condition should not have surprised the producers. When soliciting comments for the 1988 rulemaking that led to reiteration of the marketable condition rule in regulation 206.152, the agency entertained suggestions from producers that the government lessor should share treatment costs, by allowing producers to deduct all post-production costs under the theory that royalties are “due on the market value of production at the lease or well.” 58 Fed.Reg. at 1252. Otherwise, industry commentators argued, MMS would “improperly sweep[] all post-production operations under the holding of [California Co.].” Id. MMS considered but rejected this suggestion, concluding that “so-called post-production costs ... [generally ... are not allowed as a deduction because they are necessary to make production marketable.” Id. at 1253.

The producers alternatively contend that, because there is an established demand for untreated gas, sales of such gas at the wellhead should be treated as “typical” for defining marketable condition. It is true that fifteen to twenty percent of the gas purchased from the producers was consumed locally, and it is plausible to conclude that contracts for one-fifth of a product are common enough to be “typical.” But it is just as plausible to read typicality as embracing the most common use and sale of gas from the area, and it is not at all obvious from the text and purposes of the regulations that contracts for one-fifth of the gas should govern the regulatory treatment of the remaining eighty percent.

Finally, we disagree with the producers’ argument that the Assistant Secretary impermissibly departed from agency precedent. In Xeno, Inc., the agency concluded gas was in marketable condition at the wellhead based on evidence of competing purchase offers there. 134 I.B.L.A. 172, 180-84 (1975). Central to Xeno, however, was the fact that the gas was suitable for pipeline access before gathering and compression, a quality reflected in its price at the wellhead. See id.; see also Amerada Hess Carp. v. Dep’t of Interior, 170 F.3d 1032, 1037 (10th Cir.1999) (distinguishing Xeno when a producer had not shown gas was in marketable condition at the wellhead).

Nor is Beartooth Oil & Gas Co. v. Lujan, No. 92-99 (D.Mont. Sept. 22, 1993), to the contrary. Beartooth overruled a decision that, in assessing royalties on wellhead sales, included the value of subsequent compression and delivery by a purchaser. Even if this unpublished district court opinion — withdrawn after a settlement — bound MMS, it is readily distinguishable. The Beartooth court ruled for the producer not because the court was certain the gas was in marketable condition at the wellhead, but rather because the agency did not make findings supporting the assertion that the gas was not. See Beartooth at 9-10. Here, the Assistant Secretary explained in detail why the gas was not in marketable condition at the wellhead. See Amoco Decision at 9-11; ARCO/Vastar Decision at 6-7.

III.

The Assistant Secretary allowed the producers to deduct from gross proceeds the costs of transporting the royalty-bearing methane and the three percent carbon dioxide “waste product” to the treatment plant, but not the costs of transporting and removing the excess carbon dioxide. The producers argue that some or all of the costs of ridding the gas of excess carbon dioxide should be deductible from gross proceeds as a cost of transporting the gas to market under 30 C.F.R. § 206.157(a)-(b).

To argue that all the extra costs are deductible, the producers liken these expenses to “firm demand” charges — nonrefundable deposit payments required to reserve pipeline capacity. DOI argued that such charges were not related to transportation in IPAA, but we did not accept DOI’s argument. See 279 F.3d at 1042 (“While some reason may lurk behind the government’s position, it has offered none, and we have no basis for sustaining its conclusion.”). The producers contend that, like firm demand charges, the costs at issue here are necessary to secure access to a mainline system that will not accept gas with a carbon dioxide content of more than two or three percent. In support of their argument, they also cite two other cases purportedly regarding pre-pipeline treatment as a transportation cost: Exxon Corp., 118 I.B.L.A. 221 (1991) and Marathon Oil Co. v. United States, 604 F.Supp. 1375 (D.Alaska 1985).

Unlike the case in IPAA, however, here the Assistant Secretary has explained why the costs at issue are not properly considered transportation costs: because removal of the excess carbon dioxide was necessary to place the gas in marketable condition, those same costs could not be part of the transportation allowance. The logic of the regulations bars an expenditure to place gas in marketable condition from also being an expenditure deductible from gross proceeds as a transportation cost. See 30 C.F.R. § 206.152(i) (lessees must “place gas in marketable condition at no cost to the Federal Government”). Because we uphold the Assistant Secretary’s conclusion that these costs are necessary to place the gas in marketable condition, we cannot quarrel with her rejection of the producers’ transportation theory. Unsurprisingly, none of the cases the producers cite deals with deducting costs necessary for placing gas in marketable condition. The firm demand charges to reserve space on the pipeline at issue in IPAA, for example, related solely to transportation and had nothing to do with conditioning the gas for market. See IPAA, 279 F.3d at 1042; see also Marathon Oil, 604 F.Supp. at 1386 (costs of liquefying natural gas deductible because done “for purposes of storage or shipment” and end-product “chemically identical to the natural gas at the lease”); Exxon Co., 118 I.B.L.A. at 242 (deductible dehydration of gas “was not performed to satisfy market specifications”).

Seeking at least half a loaf, the producers argue the Assistant Secretary erred in treating the excess carbon dioxide (the amount beyond the pipeline threshold) as a non-royalty-bearing product, whose transportation cost is nondeductible. The producers contend that the carbon dioxide in excess of the pipeline tolerance should have been treated the same as that within the tolerance — as a waste product — with the result that the deductible transportation cost would not be reduced by the cost of transporting any of the carbon dioxide.

Although carbon dioxide is carbon dioxide, there is a meaningful distinction in the regulation between the amount that may be marketed along with the gas, and the excess that must be removed to make the gas marketable. The two amounts need not be treated the same under the rules, simply because they are the same product. Within the pipeline tolerance, carbon dioxide is a waste product because it need not be removed to place the gas in marketable condition; beyond the tolerance, the carbon dioxide is a non-royalty-bearing product that must be removed for the gas to considered marketable under the rules. This difference has the consequence ascribed by the Secretary when it comes to determining the deductibility of transportation costs.

The producers rely on an illustrative example in the MMS-issued Payor Handbook that treats carbon dioxide in a manner suggesting it is waste. This example — which does not purport to be a rule and concerns a carbon dioxide content of only one percent, see 3 Minerals Mgmt. Serv., U.S. Dep’t of the Interior, Oil & Gas Payor Handbook § 6.4.1 (1993) — hardly compels the agency to treat a ten percent component of carbon dioxide as waste, let alone creates an inference that carbon dioxide is always waste.

IV.

The producers also challenge the Payor Letter cited in the orders and in the Assistant Secretary’s decisions, arguing that it constituted a new rule the agency could promulgate only through notice and comment rulemaking. See 5 U.S.C. § 551(4) (defining a rule as “the whole or part of an agency statement of general or particular applicability and future effect designed to implement, interpret, or prescribe law or policy or describing the organization, procedure or practice requirements of an agency”). Rejecting the Assistant Secretary’s explanation that the Payor Letter was merely an interpretation of existing regulations, the producers ask us to set it aside and consider the Assistant Secretary’s reliance upon it unlawful because the agency did not promulgate the rule as required by the Administrative Procedure Act. See id. § 553(b)(3)(A).

This challenge is governed by Indep. Petroleum Ass’n of Am. v. Babbitt, which held that a similar MMS letter was not a rule subject to the notice and comment requirement. 92 F.3d 1248, 1256-57 (D.C.Cir.1996). As in Babbitt, the Payor Letter here is not an agency statement with future effect because nothing under DOI regulations vests the Letter’s author — in Babbitt and this case MMS’s Associate Director for Royalty Management — with the authority to announce rules binding on DOI. Id. at 1256. “The letter is not an agency rule at all, legislative or otherwise, because it does not purport to, nor is it capable of, binding the agency.” Id. at 1257.

The producers attempt to distinguish Babbitt by alleging that here the agency adopted the Payor Letter’s positions when it issued and affirmed the orders. But nothing in the decisions under review suggests that the agency viewed the Payor Letter as authoritative or binding; the agency in those decisions applied the pertinent statutes and regulations with no determinative reliance on the Payor Letter. The agency decisions reached the same result as the guidance in the Payor Letter, but that was true in Babbitt as well. The sort of “workaday advice letter[s] that agencies prepare countless times per year in dealing with the regulated community,” Indep. Equip. Dealers Ass’n v. EPA, 372 F.3d 420, 427 (D.C.Cir.2004) (internal quotation marks omitted), do not retroactively become agency rules whenever they are referenced in an agency decision.

V.

Finally, the producers argue that the district court and the Assistant Secretary erred in concluding that the MMS orders assessing additional royalties were not barred by the statute of limitations found at 28 U.S.C. § 2415(a). That provision specifies that

[Ejvery action for money damages brought by the United States or an officer or agency thereof which is founded upon any contract express or implied in law or fact, shall be barred unless the complaint is filed within six years after the right of action accrues or within one year after final decisions have been rendered in applicable administrative proceedings required by contract or by law, whichever is later.

The threshold question is whether an administrative order assessing additional royalties can reasonably be understood to be an “action for money damages” initiated by the filing of a “complaint.” The phrase “action for money damages” points strongly to a suit in a court of law, rather than an agency enforcement order that happens to concern money due under a statutory scheme. See Black’s Law Dictionary 389 (6th ed.1990) (defining “damages” as “pecuniary compensation or indemnity, which may be recovered in the courts”); OXY USA, Inc. v. Babbitt, 268 F.3d 1001, 1010 (10th Cir.2001) (en banc) (Briscoe, J., dissenting) (“Taken together, the entire phrase plainly and indisputably refers to lawsuits brought by the federal government seeking compensatory relief for losses suffered by the government.”).

Any doubt is removed by the fact that subsection 2415(a) measures the limitations period from the filing of a “complaint.” It strains legal language to construe this administrative compliance order as a “complaint” for money damages in any ordinary sense of the term. See Black’s Law Dictionary 285 (6th ed.1990) (defining complaint as an “initial pleading” under “codes or Rules of Civil Procedure” that contains, inter alia, a “statement of the grounds upon which the comt’s jurisdiction depends”) (emphasis added). Although some statutes provide for a “complaint” that triggers administrative proceedings, see, e.g., 5 U.S.C. § 1215(a)(1); 15 U.S.C. §§ 45(b), 522; 25 U.S.C. § 2713(a)(3); 29 U.S.C. § 160(b), adjudicative hearings on the merits follow such filings. Here MMS issued an order, the defiance of which incurs a “Notice of Noncompliance” and subsequent civil penalties, absent a successful appeal. See 30 C.F.R. § 241.51 (1996); see also Black’s Law Dictionary 1096 (6th ed.1990) (defining order as “[a] mandate; precept; command or direction authoritatively given; rule or regulation”).

While we are satisfied from the text of subsection 2415(a) that the agency action at issue here does not fall under the clause’s purview, the statute as a whole is admittedly less clear. One of the statute’s enumerated exceptions — added more than 16 years after the passage of the original Act, see Debt Collection Act of 1982, Pub.L. No. 97-365, § 9, 96 Stat. 1749, 1754 —states that “[t]he provisions of this section shall not prevent the United States or an officer or agency thereof from collecting any claim of the United States by means of administrative offset, in accordance with section 3716 of title 31.” 28 U.S.C. § 2415(i). The producers contend that subsection 2415(a) must apply to administrative proceedings' generally,- or there would have been no need to except administrative offsets in subsection (i).

This argument is not without force. It is a familiar canon of statutory construction that, “if possible,” we are to construe a statute so as to give effect to “every clause and word,” United States v. Menasche, 348 U.S. 528, 538-39, 75 S.Ct. 513, 99 L.Ed. 615 (1955) (internal quotation marks omitted), and the producers’ argument has helped convince two other circuits that subsection 2415(a) can apply to other administrative proceedings, see OXY USA, 268 F.3d at 1006; United States v. Hanover Ins. Co., 82 F.3d 1052, 1055 (Fed.Cir.1996). In this case, however, the inference to be drawn from the addition of subsection 2415(i) does not dissuade us from the more natural reading of the express language of subsection 2415(a). As the Supreme Court recently explained, “our preference for avoiding surplusage constructions is not absolute.” Lamie v. U.S. Trustee, 540 U.S. 526, 124 S.Ct. 1023, 1031, 157 L.Ed.2d 1024 (2004). See Chickasaw Nation v. United States, 534 U.S. 84, 89, 122 S.Ct. 528, 151 L.Ed.2d 474 (2001) (adopting construction that leads to surplusage because “we can find no other reasonable reading of the statute”). No canon of construction justifies construing the actual statutory language beyond what the terms can reasonably bear. See Conn. Nat’l Bank v. Germain, 503 U.S. 249, 252-53, 112 S.Ct. 1146, 117 L.Ed.2d 391 (1992).

The context surrounding the passage of subsection 2415(i) gives us some comfort that the provision is not so much surplus-age as the result of a congressional effort to moot a debate between the Justice Department and the Comptroller General about the reach of subsection 2415(a) in the context of administrative offsets. The Justice Department thought subsection 2415(a) might be invoked to bar administrative offsets; the Comptroller General concluded that it was not applicable in that context. The Comptroller General nevertheless recommended that Congress enact subsection 2415(i) “as a means of resolving the differences between us.” Debt Collection Act of 1981: Hearings on S. 1219 before the Senate Committee on Governmental Affairs, 97th Cong. 83 (1981) (statement of Milton J. Socolar, Acting Comptroller General). “By adopting section 2415(i), Congress thus did not have to decide whether the Department of Justice or the Comptroller General had the better of the argument as to the proper construction of the pre-1982 version of section 2415.” Hanover Ins. Co., 82 F.3d at 1057 (Bryson, J., dissenting). We think it clear that subsection 2415(a), by its terms, does not cover administrative actions, and the fact that Congress “sought to make [the] statute crystal clear rather than just clear” in the context of administrative offsets does not alter our conclusion. In re Collins, 170 F.3d 512, 513 (5th Cir.1999).

Finally, buttressing our conclusion not to let subsection 2415(i) alter the clear import of 2415(a) is the opposing canon (there always seems to be one) that statutes of limitations against the sovereign are to be strictly construed. See E.I. du Pont de Nemours & Co. v. Davis, 264 U.S. 456, 462, 44 S.Ct. 364, 68 L.Ed. 788 (1924); Hanover Ins. Co., 82 F.3d at 1057 (Bryson, J., dissenting). Expanding the apparent scope of a statute of limitations beyond its plain language by inference from an express exception is hardly strict construction. Similar concerns helped dissuade the Supreme Court from relying on the surplusage canon in Chickasaw Nation. See 534 U.S. at 90, 122 S.Ct. 528 (application of surplusage canon would contravene rule that Congress ordinarily enacts tax exemptions explicitly).

Although other courts addressing this question have emphasized the underlying purpose of repose animating section 2415, see OXY USA, 268 F.3d at 1005-06; Hanover Ins. Co., 82 F.3d at 1055, the Supreme Court has frequently warned that such appeals to purpose cannot override a statute’s clear language, see, e.g., Badaracco v. Comm’r of Internal Revenue, 464 U.S. 386, 398, 104 S.Ct. 756, 78 L.Ed.2d 549 (1984) (“Courts are not authorized to rewrite a statute because they might deem its effects susceptible of improvement. This is especially so when courts construe a statute of limitations, which must receive a strict construction in favor of the Government.”) (internal quotation marks and citation omitted). Consequently, we join the Fifth Circuit, see Phillips Petroleum Co. v. Johnson, No. 93-1377, 1994 WL 484506 (5th Cir. Sept. 7, 1994), in concluding that the statute of limitations in subsection 2415(a) does not apply to bar an administrative order demanding payment owed pursuant to the MLA and its regulations.

Because we conclude that the government’s demand for additional royalties is not an action for money damages initiated by the filing of a complaint, we do not need to address the government’s further arguments that the demand neither seeks “money damages” nor is “founded upon a contract.” 28 U.S.C. § 2415(a).

The judgment of the district court is

Affirmed. 
      
      . The dispute about the applicability of 28 U.S.C. § 2415(a) to demands for additional royalties is no longer a live one with respect to production after September 1, 1996, for which Congress has set a seven-year limitations period. See Federal Oil and Gas Royalty Simplification and Fairness Act of 1996, Pub.L. No. 104-185, 110 Stat. 1700 (codified at 30 U.S.C. § 1724).
     