Amoco Prodn Co v. Watson, Rebecca W. , 410 F.3d 722 ( 2005 )

United States Court of Appeals
FOR THE DISTRICT OF CO LUM BIA 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 produc-
ers 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 landown-
ers, 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
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 interpre-
tation 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 “unmarket-
able” 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 market-
able 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 pro-
ceeds” 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)(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 primar-
ily 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 Ser-
vice’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 pur-
chaser. 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 con-
tended 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 sum-
mary 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 govern-
ment 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 “con-
trolling 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 market-
able 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 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 (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 “so-
called 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 pur-
chaser. 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 condi-
tion 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 produc-
ers 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 transporta-
tion allowance. The logic of the regulations bars an expenditure
to place gas in marketable condition from also being an expendi-
ture 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 market-
able 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 Assis-
tant 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 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
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
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 appli-
cable 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-
1
The dispute abou t the ap plicability 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 C ongress has set a
seven-year limitations period. See Federal O il and Gas Royalty
Simplification and Fairness Act of 1996, Pub. L. No. 104-185, 110
Stat. 1700 (codified at 30 U .S.C. § 1724).
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 “state-
ment of the grounds upon which the court’s jurisdiction de-
pends”) (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 Collec-
tion 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 subsec-
tion 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 Govern-
mental 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 Chicka-
saw 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 subsec-
tion 2415(a) does not apply to bar an administrative order
demanding payment owed pursuant to the MLA and its regula-
tions.
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.