United States Court of Appeals

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued February 14, 2005 Decided June 10, 2005

No. 04-5006

AMOCO PRODUCTION COMPANY,

APPELLANT

v.

REBECCA W. WATSON, ASSISTANT SECRETARY FOR LAND

AND MINERAL MANAGEMENT, ET AL.,

APPELLEES

Consolidated with

04-5007

Appeals from the United States District Court

for the District of Columbia

(No. 00cv01480)

(No. 00cv02933)

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.
2

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 of ten 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.
3

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 producerlessees 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
4

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(i). 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 nonroyalty bearing products. See id. § 206.157(a)(2)(i), (b)(3)(i).

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.”
5

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)(i), (b)(3)(i). 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, produc-
6

ers 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 $782,373, 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
7

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).
8

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 (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. 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.

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
9

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 represent[ed] 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, 487 U.S. at 843. 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 interpre-
10

tation 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 (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 (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 CO2 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
11

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 outermost 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 (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.”

53 Fed. Reg. at 1252. Otherwise, industry commentators

argued, MMS would “improperly sweep[] all post-production
12

operations under the holding of [California Co.].” Id. MMS

considered but rejected this suggestion, concluding that “socalled post-production costs . . . [g]enerally . . . 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 Corp. 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
13

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).
14

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 endproduct “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. 
15

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 MMSissued 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
16

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
17

1 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).

limitations found at 28 U.S.C. § 2415(a).1 That provision

specifies that

[E]very 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 compli-
18

ance 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 court’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 (1955) (internal

quotation marks omitted), and the producers’ argument has
19

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, 124 S. Ct. 1023, 1031 (2004).

See Chickasaw Nation v. United States, 534 U.S. 84, 89 (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 (1992). 

The context surrounding the passage of subsection 2415(i)

gives us some comfort that the provision is not so much

surplusage 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. 1249 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
20

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 (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 (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 (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 (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.
21

 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.