Opinion for the Court filed by Senior Circuit Judge WILLIAMS.
Concurring opinion filed by Circuit Judge SENTELLE.
STEPHEN F. WILLIAMS, Senior Circuit Judge:Producers of natural gas typically lease the mineral rights and compensate the owner by means of a royalty calculated as some fraction (such as $ or %) of the value of the gas produced. In exchange, lessees agree to bear the costs and risks of exploration and production. Federal and Indian gas leases are no exception.
But the federal government is not your standard oil-and-gas lessor. For the detailed ascertainment of the parties’ rights, its leases give controlling effect not merely to extant Department of Interior regulations but also to ones “hereafter promulgated.” See, e.g., Department of Interior, Form 3100-11, at p. 1 (1992). The regulations have historically called for calculation of royalty on the basis of “gross proceeds.” See, e.g., 30 C.F.R. §§ 206.152(h) (federal unprocessed gas), 206.153(h) (federal processed gas). But to abide by the statutory mandate to base royalty on the “value of the production removed or sold from the lease,” 30 U.S.C. § 226(b)(1)(A), Interior has allowed two deductions from gross proceeds when calculating value for royalty purposes. One deduction relates to certain processing costs and is irrelevant here; the other is for transportation costs when production is sold at a market away from the lease. 30 C.F.R. §§ 206.157, 206.177; see also Final Rule, Revision of Oil Product Valuation Regulations and Related Topics, 53 Fed. Reg. 1184, 1186 (1988). These are evidently the only deductions from gross proceeds. Walter Oil & Gas Corp., 111 IBLA 260, 265 (1989). Marketing costs have therefore not been *1038deductible. See, e.g., Arco Oil & Gas Co., 112 IBLA 8, 10-11 (1989).
In the mid-1980s a series of rulemak-ings by the Federal Energy Regulatory Commission somewhat changed the circumstances to which these principles applied. Previously, producers most commonly sold gas at the wellhead to natural gas pipeline companies, which then transported it and sold it to local distribution companies; less commonly, they made direct sales from producer to an end user or distributor, with the pipeline providing only transportation. See, e.g., FPC v. Transcontinental Gas Pipe Line Corp., 365 U.S. 1, 4, 81 S.Ct. 435, 5 L.Ed.2d 377 (1961). But FERC, starting with Order No. 436 and culminating in Order No. 636, in effect transformed the pipelines into “open-access” transporters and required them to separate sales from transportation services, Final Rule, Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation, and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 57 Fed. Reg. 13,267, 13,279/1 (1992) (“Order 636”), to charge unbundled rates for services such as transmission and storage, id. at 13,288-89, and to assign their merchant services to functionally independent market affiliates, id. at 13,298; see also 18 C.F.R. § 161 (1988) (restricting pipelines from favoring such affiliates). In effect, the pipelines as such became almost exclusively transporters of gas, and direct sales by producers to end users, distributors, or merchants became the norm.
In response to these changes, the Department of Interior in 1997 amended its gas royalty regulations “to clarify [its] existing policies” and to prevent lessees from claiming “improper deductions on their royalty reports and payments.” Final Rule, Amendments to Transportation Allowance Regulations for Federal and Indian Leases to Specify Allowable Costs and Related Amendments to Gas Valuation Regulations, 62 Fed. Reg. 65,753/3-65,-754/1 (1997) (“Final Rule”). Two trade associations representing the gas producers (American Petroleum Institute for the “majors,” Independent Petroleum Association of America for the “independents”) brought suits challenging these regulations as arbitrary and capricious. Their primary contention was that Interior had im-permissibly refused to permit deductions for costs incurred in marketing gas to markets “downstream” of the wellhead. Dispute focused especially on Interior’s denial of deductions for (1) fees incurred in aggregating and marketing gas with respect to downstream sales; (2) “intra-hub transfer fees” charged by pipelines for assuring correct attribution of quantities to particular transactions (not for the physical transfers themselves); and (3) any “unused” pipeline demand charge (i.e., the portion of a demand charge paid to secure firm service but relating to quantities in excess of a producer’s actual shipments).
The district court granted summary judgment for the producers in broad terms, Independent Petroleum Association of America v. Armstrong, 91 F.Supp.2d 117, 130 (D.D.C.2000) (“IPAA”), but then granted Interior’s Rule 59(e) motion for clarification, Independent Petroleum Association of America v. Armstrong, No. 98-00531(RCL) (D.D.C. Sept. 1, 2000) (“Amended Order”) (unpublished opinion). When the dust had settled, the upshot was to declare that the relevant regulations were unlawful “to the extent that they impose a duty on lessees to market gas downstream ... and disallow the deduction of downstream marketing costs,” including the intra-hub transfer fees, and to the extent that they limit deduction for firm demand charges to the applicable rate multiplied by the “actual volumes transported.” Amended Order, slip op. at 2. The modified order also specified that a *1039producer that sold unused pipeline capacity must credit the United States with the resulting revenue. Id. Interior now appeals.
We review the district court’s ruling de novo, “as if the [agency’s] decision had been appealed to this court directly.” Kosanke v. Dep’t of Interior, 144 F.3d 873, 876 (D.C.Cir.1998) (quoting Dr. Pepper/Seven-Up Cos. v. FTC, 991 F.2d 859, 862 (D.C.Cir.1993)). On the deductibility of marketing costs we find no legal error in Interior’s rule and therefore reverse the district court; on the “unused” demand charge issue, we affirm the district court.
The producers argue that we owe no deference to Interior’s judgments here, saying that the case involves interpretation of contracts, not of a statute. Thus they call for “interpretation under neutral principles of contract law, not the deferential principles of regulatory interpretation.” Mesa Air Group, Inc. v. Department of Transportation, 87 F.3d 498, 503 (D.C.Cir.1996). But see National Fuel Gas Supply Corp. v. FERC, 811 F.2d 1563, 1570-71 (D.C.Cir.1987) (applying a Chevron framework to agency interpretation of contracts, though expressing concern where the agency is self-interested). Thus the producers’ briefs point (rather summarily) to state court decisions, implicitly asking us to treat the matter as would a state court interpreting private leases. But here the contracts themselves lead us back to the agency. As we said, they incorporate the regulations and recognize Interior’s authority to modify them. E.g., Form 3100-11, at p. 1 (“Rights granted are subject ... to regulations and formal orders hereafter promulgated when not inconsistent with lease rights granted or specific provisions of this lease.”); id. at § 2 (reserving to Interior “the right to establish reasonable minimum values on products”); see also, e.g., Department of Interior, Form MMS-2005, § 6(b) (1986); Department of Interior, Form BAO-436A, § 3 (1993).
Of course the application of new rules to pre-existing leases may involve “secondary retroactivity”: a new rule that legally has only “future effect,” and is therefore not subject to doctrines limiting retroactive effect, may still have a serious impact on pre-existing transactions. See, e.g., Bowen v. Georgetown University Hospital, 488 U.S. 204, 219-20, 109 S.Ct. 468, 102 L.Ed.2d 493 (1988) (Scalia, J., concurring). Interior’s own rules recognize the possibility, explicitly repudiating any authority to alter the royalty rate except downwards (i.e., in the lessee’s favor). 30 C.F.R. § 202.52(a). The legal effect of such secondary retroactivity is to add a nuance to ordinary review for whether the agency has been arbitrary or capricious: we review to see whether disputed rules are “reasonable, both in substance and in being made retroactive.” U.S. Airwaves, Inc. v. FCC, 232 F.3d 227, 233 (D.C.Cir.2000). But this added nuance is quite different from a general denial of deference.
In a related argument, producers urge that deference to Interior’s interpretation of the statute under Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837, 104 S.Ct. 2778, 81 L.Ed.2d 694 (1984), is inappropriate for regulations that affect contracts in which Interior has financial interests.
But in the mineral leasing statutes Congress has granted rather sweeping authority “to prescribe necessary and proper rules and regulations and to do any and all things necessary to carry out and accomplish the purposes of [the leasing statutes].” 30 U.S.C. § 189 (federal lands); see also 25 U.S.C. §§ 396, 396d (tribal lands); 43 U.S.C. § 1334(a) (outer Continental shelf). These “purposes,” of course, include the administration of federal leas*1040es, which involves collecting royalties and determining the methods by which they are calculated. See California Co. v. Udall, 296 F.2d 384, 387-88 (D.C.Cir.1961); see also Independent Petroleum Association v. Babbitt, 92 F.3d 1248, 1262 n. 6 (D.C.Cir.1996) (Rogers, J., dissenting) (recognizing that Congress authorized Interior “to prescribe regulations governing mineral leases”).
It is thus not surprising that the cases do not support producers’ theory. Though no circuit appears ever to have ruled specifically on the issue of deference to financially self-interested agencies, courts have regularly applied Chevron in royalty cases. In California Co., we deferred to Interior’s interpretation of the word “production” for purposes of calculating royalty, noting the Department’s duties both to protect the public interest in royalties and to assure “incentive[s] for development.” 296 F.2d at 388. Similarly, in Mesa Operating Limited Partnership v. Department of Interior, 931 F.2d 318 (5th Cir.1991), the Fifth Circuit applied Chevron in determining whether certain reimbursements were subject to royalty. Id. at 322; see also Enron Oil & Gas Co. v. Lujan, 978 F.2d 212, 215 (5th Cir.1992) (applying Chevron to issue of whether state tax reimbursements are subject to royalty); Marathon Oil Co. v. United States, 807 F.2d 759, 765-66 (9th Cir.1986) (applying Chevron to Interior’s use of a “net-back” method for calculating value for royalty purposes). Our reference in California Co. to Interi- or’s necessary concern for producer incentives in effect invoked Interior’s role as a repeat player, which would cause Interior to pay severely if it acquired a reputation for pulling the rug out from under the generally accepted meaning of existing leases.
In support of their position, producers principally rely on language from Transohio Savings Bank v. Office of Thrift Supervision, 967 F.2d 598 (D.C.Cir.1992), where we expressed reluctance to apply Chevron “to an agency interpretation of a statute that will affect agreements to which the agency is party.” Id. at 614. But we ultimately found that Congress’s intent was clear and thus had no occasion to grant (or withhold) deference. See id. at 614-15. In the end, of course, the availability of Chevron deference depends on congressional intent, but our application of such deference in the face of a recognized risk of agency self-aggrandizement, such as interpretations of their own jurisdictional limits, Oklahoma Natural Gas Co. v. FERC, 28 F.3d 1281, 1283-84 (D.C.Cir.1994), necessarily means that self-interest alone gives rise to no automatic rebuttal of deference. Indeed, given the ubiquity of some form of agency self-interest, see generally Dennis C. Mueller, Public Choice 156-70 (1979); William A. Niskanen, Jr., Bureaucracy and Representative Government (1971), a general withdrawal of deference on the basis of agency self-interest might come close to overruling Chevron, a decision far beyond our authority. We see no indication here of a special intent to withhold deference.
* * *
“Downstream” marketing costs and intra-hub transfer fees. We find nothing unreasonable in Interior’s refusal to allow deductions for so-called “downstream” marketing costs. See Final Rule, 62 Fed. Reg. at 65,756. Both the producer groups acknowledge that marketing costs for sales at the lease have historically been nondeductible. API Br. at 30; IPAA Br. at 22. Yet at no point do they offer a persuasive reason for introducing a distinction between marketing for leasehold sales and for “downstream” sales. Indeed, marketing does not even appear readily divisible between the two, as it would be if lessees stood on their lease boundaries and *1041operated the equivalent of a lemonade stand for leasehold sales, but traveled to distant cities for “downstream” ones. Rather, so far as it appears, marketing proceeds by means of the standard modern devices — face-to-face meeting, phone call, internet posting. See, e.g., Order 636, 57 Fed. Reg. at 13,282/2 (describing electronic bulletin boards, then precursors to the Internet, as having become “standard indus-trywide practice”). Unlike the sale itself, which will presumably involve shifts of title and possession at specified points, marketing has no locus — certainly none that ineluctably tracks the point where title shifts.
To be sure, transaction costs may be higher for sales in the current market; sales to a single (perhaps monopsonistic) pipeline may have been painfully simple. But a change in the dimension of a cost is hardly an argument for its reclassification, as the Interior Board of Land Appeals has observed. Arco, 112 IBLA at 11. And because the producers are under no duty to market “downstream” and may opt to sell at the leasehold, see IPAA, 91 F.Supp.2d at 123 (“Interior concedes that plaintiffs are free to sell or beneficially consume gas at the wellhead only, rather than pursue downstream sales.”), a complaint based on the cost change is especially weak.
Producers further argue that downstream marketing adds to the value of the gas at the leasehold, and thus that the royalty owner should share the costs. In support, they propose what amounts to an elegant theory suggesting that the sale of “marketable condition” gas at the leasehold represents a baseline, and that the costs of all further value-adding activities should be deductible. Under this view, producers explicitly condemn any distinction between marketing and transportation. But the argument in the end seems almost metaphysical; it is a claim that when the maximum value of gas can be realized by a downstream sale, then not only transportation costs but also the cost of efforts undertaken to identify and realize that value must somehow be more like transportation itself than they are like on-lease marketing.
Assuming arguendo that producers’ metaphysical point is correct, we think it falls far short of compelling the Department to give up its usual distinction between marketing and transporting costs. Not only is the distinction traditional, Walter Oil, 111 IBLA at 265, but Interior has historically applied it to downstream sales, denying deductibility for a lessee’s costs in hiring a marketing agent to arrange transportation downstream, to aggregate customers, and to deal with a local distribution company. Arco, 112 IBLA at 9-12. Given the difficulty in slicing up marketing costs on the basis of the point of sale, and given that Interior must take administrability into account, compare Owen L. Anderson, “Royalty Valuation: Should Royalty Obligations Be Determined Intrinsically, Theoretically, or Realistically? (Part 2),” 37 Nat. Resources J. 611, 678 (1997) (discussing monitoring problems), we find nothing unreasonable in its hewing to the old line between marketing and transportation.
The producers’ attack on Interior’s denial of deductibility for aggregator/marketer fees, 30 C.F.R. §§ 206.157(g)(2), 206.177(g)(2), rests on the same foundations as the more general attack on “downstream” marketing costs and therefore fails for the same reasons. Intra-hub transfer fees, id. at §§ 206.157(g)(4), 206.177(g)(4), are slightly different. As IPAA recognizes, intra-hub transfer fees are charged “when [a] lessee sells the gas at [the] pipeline’s junction at the hub.” IPAA Br. at 30 (emphasis added). Interi- or distinguishes these fees, which are part of a “sales transaction,” from so-called intra-hub wheeling fees, which are charged *1042for the actual transportation of gas through a hub. See Final Rule, 62 Fed. Reg. at 65758. Producers contend that Interior allowed deduction for these costs in the past and failed to justify its change in policy. Before FERC Order No. 636, costs of this sort, even though reasonably classifiable as marketing, would have been bundled with transportation costs, making precise separation administratively troublesome, if not impossible. Once Order No. 636 unbundled rates and enabled Interior to identify “nonallowable costs of marketing,” Final Rule, 62 Fed. Reg. at 65755/1, it was reasonable for Interior to rigorously apply its conventional distinction between marketing and transportation.
Producers make two additional arguments regarding intrahub transfer fees. First, they seem to claim that Interior had the ability to “look behind” the bundled rates prior to 1997. But their citations to regulations governing deductions in the non-arms-length bargaining context, see 30 C.F.R. § 206.157(b)(2)(i) & (iii), offer little support. Indeed, they seem only to further demonstrate Interior’s historical reluctance to separate actual transportation costs from “nonallowable costs of marketing” when such separation is administratively difficult. Second, they argue that intra-hub transfer fees are similar to other administrative costs, such as -Gas Supply Realignment, Annual Charge Adjustment, and Gas Research Institute fees, which are deductible. Producers fail to note, however, that these are mandatory surcharges imposed by FERC on gas transportation, and thus, unlike intrahub transfer fees, can be considered part of the actual cost of transporting gas. See Final Rule, 62 Fed. Reg. at 65758.
“Unused” firm demand charges. Shippers of natural gas may choose among different degrees of assurance that space will be available for their shipments, paying (naturally) for extra security. By paying a firm demand charge (an upfront reservation fee), they secure a guaranteed amount of continuously available pipeline capacity; when they actually ship, they incur a “commodity charge” for the transport itself. The reservation fee, however, is nonrefundable — the cost of any reserved capacity that a lessee ultimately cannot use will be lost unless it is able to resell the capacity. (Recall that the district court amended the summary judgment order, at the behest of the government, to provide for a credit to the government in the event of such resales.) In contrast, with “interruptible” service, shippers pay no reservation fee, but their access to pipeline capacity is subject to the changing needs of other, higher priority customers (i.e., those who pay for firm demand). Producers claim that the unused firm demand charges are part of their actual transportation costs, and thus should be deductible.
In defense of its contrary view, Interior said only that it does “not consider the amount paid for unused capacity as a transportation cost,” Final Rule, 62 Fed. Reg. at 65757/1, not revealing to what category such expenses did belong. In its opening brief, it quotes its prior assertion and declares that the district court must be reversed because it “offered no cogent reason for rejecting this distinction.” Interior Br. at 43. But Interior has offered no “distinction” at all, only an unusually raw ipse dixit. On its face, it is hard to see how money paid for assurance of secure transportation is not “for transportation”; the cost of freight insurance looks like a shipping expense, for example, even if the goods arrive without difficulty and the premium therefore goes “unused.” And Interior makes no suggestion that producers have incurred such fees extravagantly — an extravagance that seems unlikely, as under the ordinary 1/8 lease the *1043producer would bear 7/8 of the loss. Further, under the crediting arrangement provided by the district court order, the government will share in any recovery of the “unused” charge, a recovery that producers have strong incentives to pursue. While some reason may lurk behind the government’s position, it has offered none, and we have no basis for sustaining its conclusion. See, e.g., Motor Vehicle Manufacturers Ass’n, Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43, 103 S.Ct. 2856, 77 L.Ed.2d 443 (1983).
The judgment of the district court is reversed on all issues except for its ruling on unused firm demand charges, which we affirm.
So ordered.