Independent Petroleum Ass'n of America v. Armstrong

91 F. Supp. 2d 117, 144 Oil & Gas Rep. 46, 2000 U.S. Dist. LEXIS 4153, 2000 WL 342677

• Court: District Court, District of Columbia
• Decided: March 28, 2000
• Docket: Civ. 98-00531 RCL, Civ. 98-00631 RCL
• Status: Published

Opinion

MEMORANDUM OPINION

LAMBERTH, District Judge.

Plaintiffs, two gas industry trade associations whose members hold federal and Indian gas leases, challenge as arbitrary, capricious and not in accordance with law amended Department of the Interior (“Interior”) regulations (“Rule”) that impose royalties on costs incurred when lessees sell gas in downstream markets. Plaintiffs contend that the royalty obligations imposed by the Rule exceed Interior’s statutory authority under the applicable statutes and have no basis in prior regulations or the gas leases themselves. Additionally, plaintiffs advance that the new Rule draws arbitrary distinctions between similar costs and impairs the obligations of leases executed prior to the enactment of the amendments. Defendants cross-move for summary judgment, asserting that the Rule was properly enacted after notice and comment and constitutes a reasonable interpretation of the regulations that Interi- or administers and the implied covenant of the gas leases. Upon consideration of the parties’ cross-motions for summary judgment, the oppositions thereto, the record, oral argument, the applicable law, and for the reasons set forth below, the court GRANTS plaintiffs’ motions for summary judgment and DENIES defendants’ motion for summary judgment.

I. BACKGROUND

A. The Natural Gas Industry and Royalties on Federal and Indian Leases

The Department of the Interior issues and administers oil and gas leases for fed eral and Indian lands pursuant to the Mineral Leasing Act, 30 U.S.C. §§ 181-287, the Mineral Leasing Act for Acquired Lands, 30 U.S.C. §§ 351-359, Indian leasing statutes, 25 U.S.C. §§ 396a-396g, 25 U.S.C. § 396, and the Outer Continental Shelf Lands Act, 43 U.S.C. §§ 1331-1356. The leasing statutes and regulations administered by Interior require lessees to pay royalties on gas production from federal and Indian leases. These statutes provide that royalties are established by a specified percentage of the value of the gas saved, removed, or sold from the lease. See 43 U.S.C. § 1337(a)(1); 30 U.S.C. § 226; 25 C.F.R. § 211.13; 25 U.S.C. § 212.16. Interior has the sole authority to “prescribe such rules and regulations as may be necessary to carry out” the leasing provisions. 43 U.S.C. § 1334(a); 30 U.S.C. § 189; 25 U.S.C. §§ 396 and 396(d). The Minerals Management Service (“MMS”), a bureau within Interior, collects, verifies and distributes revenues from the gas leases issued under these authorities.

The American Petroleum Institute (“API”) is a nationwide trade association representing over 400 corporate members engaged in all aspects of petroleum exploration, production, refining, distribution, and marketing. API members hold oil and gas leases on federal and Indian lands. The Independent Petroleum Association of America (“IPAA”) is a trade association representing more than 5,500 producers of oil and natural gas within the United States. Many IPAA members also hold leases on federal or Indian lands.

The present controversy grows out of the re-structuring of the gas pipeline industry brought about by Federal Energy Regulatory Commission Order No. 636. Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation; and Regulation of Natural Gas Pipelines After Partial Statutes and Regulations, Order No. 636, 57 Fed.Reg. 13267 (April 16, 1992), FERC Statutes AND Regulations (CCH) ¶ 30, 950 (August 3, 1992); order on reh’g, Order No. 636-B, 57 Fed.Reg. 57911 (December 8, 1992), 61 F.E.R.C. (CCH) ¶ 61,272 (November 27, 1992). Accordingly, to appreciate the instant dispute, it is necessary to highlight lessees’ obligations as they existed prior to the amended Rule and FERC Order 636.

In the pre-FERC 636 gas market, lessees sold gas to pipelines at or near the lease. Thus, the essential bargain embodied in federal and Indian leases entitled the lessor to a royalty based upon the value of production at the lease when the lessee produced gas from the leased premises. Consistent with this practice of selling gas at the lease, royalties on federal gas leases were typically “calculated at values at the wells, not at the pipe line destination.... ” Continental Oil Co. v. United States, 184 F.2d 802, 820 (9th Cir. 1950). The basic rule on royalties, known as the “gross proceeds rule,” provides that “under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for the lease production.” 30 C.F.R. § 206.152.(h) (1995). Gross proceeds are “the total monies and other consideration accruing to an oil and gas lessee for the disposition of [gas],” minus allowances or deductions. 30 C.F.R. § 206.151 (1995).

Under the pre-existing regulations and the leases, lessees also have an express duty to place gas in marketable condition, which means that production costs are borne solely by the lessee. The marketable condition rule requires lessees to produce “lease products which 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 (1997).

In addition to the duty to place production in marketable condition, lessees have an express obligation to avoid waste. This duty can be satisfied by marketing and selling the gas at the lease or wellhead, or by beneficially consuming the production. See, e.g., California Co. v. Udall, 296 F.2d 384, 387 (D.C.Cir.1961) (construing 30 C.F.R. § 221.35 (now covered by 30 C.F.R. § 202.150(c)), which provided that a “lessee is obligated to prevent the waste of oil or gas and to avoid physical waste of the gas ...”).

Prior to FERC Order 636, producers generally did not need to incur transportation costs to locate a market for the gas, as pipelines were the primary purchasers. Accordingly, allowances for transportation costs were largely irrelevant. But when a lessee did transport gas, the lessee was required to pay a pipeline rate or tariff to transport the gas and Interior permitted the lessee to deduct the entire rate or tariff from the value it received downstream from the lease.

A producer likely sells gas away from the wellhead because it can demand a higher price in that market. Moving gas away from the wellhead to downstream markets, however, entails costs that are not incurred when gas is marketed at the lease. Thus, from an economic standpoint, the higher sale prices obtained in a downstream market are, in part, a reflection of the costs and risks involved. For example, a lessee transporting gas to a market downstream of the well will typically need to pay for the aggregation or storage of gas produced by multiple leases, in addition to the cost of getting the gas to the hub or sales point. Other fees involve the necessary costs of intermediaries such as market hub operators or for the management of market or environmental risks, or for scheduling delivery.

In the pre-FERC Order 636 gas market, all costs associated with moving gas to downstream markets were treated collectively as transportation costs and, hence, were deductible from royalty value when the point of sale was downstream from the lease. That is, when downstream sales occurred, MMS would collect a royalty based on the enhanced value of production obtained in the downstream sale. Yet at the same time, MMS shared in the costs incurred by the lessee to transport the gas to the downstream market by tracing the value of production back to the lease or wellhead by deducting those costs associated with moving the gas downstream. Thus, while reaping the benefits of a higher value downstream sale through a higher royalty, MMS did not simply free-ride on the lessees’ efforts to obtain value for the gas.

FERC Order 636 was designed to increase competition in the gas sales market by the mandatory unbundling of pipeline sales services. To that end, Order 636’s unbundling mandate was directed at gas sales by pipelines, not producers, in order to facilitate gas purchases by suppliers other than the pipelines. It was thought that this unbundling would enable the development of more competitive markets for gas at the wellhead and downstream. FERC determined that without Order 636’s unbundling, interstate pipelines would retain a substantial market advantage over alternative suppliers because pipelines included firm transportation service in their sales price and this more desirable capacity was reserved exclusively for pipelines’ own sales customers. Firm transportation capacity was, therefore, unavailable to accommodate transactions between purchasers and alternative suppliers, and such sales were relegated to spot sales using interruptible transportation. In short, pipelines’ bundling of sales and transportation precluded alternative suppliers from competing effectively in the premium firm, long-term sales market because such suppliers were unable to offer transportation service on par with that offered by pipelines.

To correct this market imbalance, Order 636 required pipelines to convert their existing bundled sales contracts into contracts for an equivalent amount of firm transportation service. Under this arrangement, pipelines could sell gas at market-based rates, but these sales would now have to compete on equal footing with the sales of non-pipeline suppliers. Accordingly, even though FERC Order 636 had a substantial effect on the identity of gas purchasers from federal and Indian leases, it did not alter the fundamentals of gas sales transactions by gas producers, and thus, did not directly alter their obligations under federal and Indian gas leases.

B. The Instant Controversy

Four years after FERC issued Order 636, Interior decided to amend its regulations on gas royalties, purportedly as a response to the demands of the changed gas market. Accordingly, on July 31, 1996, the MMS issued a Notice of Proposed Rulemaking (“NOPR”). Amendments to Transportation Allowance Regulations for Federal and Indian Leases to Specify Allowable Costs and Related Amendments for Gas Valuation Regulations, 61 Fed.Reg. 39931 (July 31, 1996). Through this informal rulemaking, the MMS proposed to amend its regulations governing valuation for royalty purposes of gas produced from federal and Indian lands. The MMS stated that it was revising its regulations as a result of FERC Order No. 636, which required, inter alia, interstate gas pipelines to separate, or un-bundle their sales services from their transportation services. Thus, the NOPR was billed as a “clarification,” which would “provide specific guidance to lessees and royalty payors” as to which transportation cost components were deductible for purposes of royalty valuation in the wake of FERC Order 636. NOPR, 61 Fed.Reg. 39,932. Specifically, MMS asserted that the unbundling achieved by FERC Order 636 now enabled MMS to isolate specific components of transportation costs that previously were not identifiable.

In addition to “clarifying” which cost allowances would be permitted after FERC Order 636, the NOPR also proposed to amend the product valuation regulations for natural gas to provide that federal lessees

must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government unless the lease agreement states otherwise. Where the value established under this section is determined by a lessee’s gross proceeds, that value shall be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the costs of which ordinarily is the responsibility of the lessee to place the gas in marketable condition or market the gas.

NOPR at Sections 206.152© and 206.153®. The same standard was proposed for Indian gas leases. NOPR at Sections 206.172© and 206.173®. This proposed requirement amended the existing regulations, which had provided only that federal and Indian lessees had an obligation “to market the production for the mutual benefit of the lessee and the lessor” and to place production “in marketable condition at no cost to the lessor.” 30 C.F.R. §§ 206.152(b)(l)(iii); 206.152®; 206.153(b)(l)(iii); 206.153®; 206.173(b)(l)(iii); 206.172®; 206.173(b)(l)(iii); 206.173®. In addition to creating an express duty to market downstream at no cost to the lessor, the NOPR proposed to disallow deductions for marketing costs for aggregator or marketing services fees, Sections 206.157(g)(2) and 206.177(g)(2), as well as firm transportation demand charges 1 for unused capacity and intra-hub title transfer fees 2 . NOPR at Sections 206.157(f)(1); 206.177(f)(1); 206.157(g)(4); 206.177(g)(4). But at the same time, however, the NOPR proposed to continue allowing the deduction for transportation costs, which include gas supply realignment costs, Gas Research Institute fees, Annual Charge Adjustment fees, commodity charges, 3 wheeling costs 4 , and long-term storage costs for gas stored over 30 days.

During notice and comment, plaintiffs filed objections to the proposed Rule, including the provision quoted above that creates an express duty on lessees to market the gas at no cost to the federal government and the proposed provisions disallowing “marketing” cost deductions. Upon conclusion of the notice and comment period, the MMS issued its final rule on December 16, 1997, which became effective on February 1, 1998. 62 Fed.Reg. 65753 (December 16, 1997). Plaintiffs’ members holding federal and Indian gas leases are presently subject to the Rule.

The final rule adopted all of the provisions contained in the NOPR, except that the provision creating an express duty to market downstream at no cost to the federal government no longer contained the phrase “unless the lease agreement states otherwise.” In adopting the terms of the NOPR, MMS again stated that

[The Rule] is necessary because components previously aggregated and unidentifiable may now be separately identified in transportation contracts, and new costs unique to the FERC Order 636 environment are emerging.

Further, some of the components reflect non-deductible costs of marketing rather than transportation.

Id. at 65753. The MMS also stated that lessees have the obligation “to incur all marketing costs.” Id. at 65756. MMS acknowledges that the Rule represents a departure from prior practice by noting that the Rule will reduce deductions from royalties because “lessees will not be able to deduct these previously bundled marketing costs.” Id. at 65755.

The dispute in this matter centers on the Rule’s effect on lessees’ royalty obligations when they sell gas downstream of the lease. Simply stated, plaintiffs object to the Rule because certain downstream costs (now labeled by MMS as “marketing costs”) previously deductible from royalty value are no longer deductible. The end result of the Rule is that lessees must now pay a royalty in excess of the value of production they received from the sale. In attacking the Rule as arbitrary and capricious, plaintiffs present a host of specific challenges. Foremost, plaintiffs dispute MMS’ suggestion that the Rule changes nothing because an implied covenant to market at no cost previously existed in the current leases. They further maintain that the Rule’s express duty to market contradicts the pre-existing contractual obligations and rights under leases executed prior to the Rule’s effective date. In addition to improperly imposing a duty to market downstream at no cost, plaintiffs argue that the Rule is invalid because MMS now disallows the deduction of downstream marketing costs from the royalty value, costs which were previously deductible. And, finally, plaintiffs assert that in treating “marketing” and “transportation” costs differently, MMS draws improper arbitrary distinctions between similar costs. On these grounds, plaintiffs seek declaratory and injunctive relief as to those portions of the Rule found to be contrary to statute, arbitrary and capricious, an abuse of discretion, and contrary to the terms of pre-existing leases.

By contrast, defendants maintain that disallowing deductions for downstream marketing costs is merely a continuation of longstanding agency policy and practice because lessees have always have had a duty to market at no cost, a duty which MMS contends is implied in the gas leases and certain prior regulations. In their cross-motion for summary judgment, defendants maintain that the Rule is entitled to deference as it manifests a reasonable exercise of Interior’s authority to define the “value” of gas production for royalty purposes. Defendants assert that the applicable statutes are silent on the issue of value for royalty purposes, and thus, according to defendants, the only question for the court is whether, when viewed through the deferential prism of Chevron U.S.A. v. Natural Resources Defense Council, 467 U.S. 837, 844, 104 S.Ct. 2778, 81 L.Ed.2d 694 (1984), the amended Rule is a reasonable way to state value for royalty purposes. In the Rule, MMS states that it “reviewed [the] current gas transportation regulations (30 C.F.R. § 206.156; 206.157; 206.176; 206.177 (1996)) and determined that they provide general authority to calculate transportation deductions for cost components resulting from implementing FERC Order 636 and previous FERC orders.” 62 Fed.Reg. 65753. And, with respect to the duty to market at no cost, MMS concedes that “the obligation to place production in marketable condition is legally distinct from the issue of marketing the gas.” Id. Instead, MMS asserts that “the implied covenant of the lease dictates that lessees must market production at no cost to the lessor.” MMS then states that “[b]oth principles [the duty to place gas in marketable condition and the duty to market at no cost] are expressly stated in the March 1, 1988, gas regulations at 30 C.F.R. §§ 206.151 and 202.151.” 62 Fed.Reg. 65756. More specifically, 30 C.F.R. § 206.151 states that “marketable condition means lease products which 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.” And, 30 C.F.R. § 202.151 provides, in relevant part, “[a] reasonable amount of residue gas shall be allowed royalty free for operation of the processing plant, but no allowance shall be made for boosting residue gas or other expenses incidental to marketing, except as provided in 30 C.F.R. § 206.”

II. DISCUSSION

Where a controversy presents no genuine issue as to any material fact, summary judgment is appropriate and the moving party is entitled to judgment as a matter of law. Fed.R.Civ.P. 56(c); FDIC v. Bender, 127 F.3d 58, 63 (D.C.Cir.1997); Diamond v. Atwood, 43 F.3d 1538, 1540 (D.C.Cir.1995). In the present matter, plaintiffs do not dispute that when they sell gas at the lease or wellhead, they must bear the costs of placing gas in marketable condition through proper conditioning or processing. This duty is imposed on lessees through .the marketable condition rule, which the parties agree is legally distinct from a duty to market gas downstream at no cost. As such, to the extent that getting gas into a suitable physical condition for sale constitutes “marketing” for purposes of selling gas at the lease, plaintiffs acknowledge that when they sell gas at the lease, they may not deduct these “marketing” costs from royalty value by virtue of the marketable condition rule. Similarly, Interior does not contend that plaintiffs have an obligation to sell gas downstream off the lease. In other words, Interior concedes that plaintiffs are free to sell or beneficially consume gas at the wellhead only, rather than pursue downstream sales. Finally, Interior acknowledges, and the court finds as a matter of fact, that the downstream marketing costs made non-deductible by the Rule, were, in fact, previously deducted by plaintiffs. See 62 Fed.Reg. 65755 (noting that the Rule will reduce deductions from royalties because “lessees will not be able to deduct these previously bundled marketing costs”). Thus, no genuine issue of material fact precludes the court from disposing of this matter on summary judgment.

Under the Administrative Procedure Act, courts must set aside agency action found to be “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” 5 U.S.C. § 706(2)(A). Thus, to sustain its actions, an agency must articulate a satisfactory explanation for its action and a rational connection between the facts found and the choice made. Motor Vehicle Mfgrs. Ass’n v. State Farm Mutual Auto. Ins. Co., 463 U.S. 29, 43, 103 S.Ct. 2856, 77 L.Ed.2d 443 (1983). An agency’s duty to explain is paramount, and “belated attempts by counsel to provide a basis for [the agency’s] choices cannot substitute for a sufficient record.” National Welfare Rights Org. v. Mathews, 533 F.2d 637, 638-39 (D.C.Cir.1976). Similarly, where an agency changes a settled course of behavior or departs from prior policy, the agency is obligated to provide in the record a reasoned analysis for the change. Motor Vehicle Mfgrs. Ass’n, 463 U.S. at 42, 103 S.Ct. 2856; see also Greater Boston Television Corp. v. FCC, 444 F.2d 841, 852 (D.C.Cir.1970) (stating that “an agency changing its course must supply a reasoned analysis indicating that prior policies and standards are being deliberately changed, not casually ignored, and if an agency glosses over or swerves from prior precedents without discussion it may cross the line from the tolerably terse to the intolerably mute”).

In all its actions, an agency is constrained by the statutory authority given by Congress. Thus, where Congress has spoken to a particular matter, Congress’ plainly expressed intent governs. Independent Petroleum Ass’n of America v. Babbitt, 92 F.3d 1248, 1255 (D.C.Cir.1996) (citing Chevron U.S.A. v. Natural Resources Defense Council, 467 U.S. 837, 844, 104 S.Ct. 2778, 81 L.Ed.2d 694 (1984)). But where a statute is silent or ambiguous with respect to a specific issue, a court must defer to the interpretation advanced by the agency that administers the statute, provided that the proffered interpretation is reasonable. Id. Judicial review of an agency’s interpretation of its regulations follows a similar standard, which also examines the reasonableness of the interpretation. Enron Oil & Gas Co. v. Lujan, 978 F.2d 212, 215 (5th Cir.1992).

As the D.C. Circuit has recognized, “Chevron review and arbitrary and capricious review overlap at the margins.” Independent Petroleum, 92 F.3d at 1258. That is, in certain cases, “the two analytic frameworks ... produce the same result.” Id. The present dispute is such a case. As such, a determination that Interior acted arbitrarily and capriciously by imposing on lessees a duty to market downstream at no cost to the lessor is the functional equivalent of finding that the agency’s interpretation of the regulations and the lease forms to contain an implied duty to market at no cost is unreasonable.

A court interpreting the terms of a government contract must examine its express terms. Thus, unlike the more solicitous standards of review under the Administrative Procedures Act, if the terms of a government contract are ambiguous, under the contra proferentem doctrine, courts will interpret them against the government as the drafter of the contract. United States v. Seckinger, 397 U.S. 203, 210, 90 S.Ct. 880, 25 L.Ed.2d 224 (1970). Indeed, no deference is due an agency’s interpretation of contracts in which it has a proprietary interest. Lockheed Martin IR Imaging Sys. Inc. v. West, 108 F.3d 319, 322 (Fed.Cir.1997); Mesa Air Group Inc. v. Dep’t of Transp., 87 F.3d 498, 508 (D.C.Cir.1996). Similarly, an agency’s interpretation of its own regulations is not entitled to deference when it will affect contracts to which the agency is a party. Transohio Sav. Bank v. Director, Office of Thrift Supervision, 967 F.2d 598, 614 (D.C.Cir.1992).

In light of these standards, the starting point for this court’s review of the validity of the Rule must begin with the relevant governing statutes. As noted above, Interior administers gas leases for federal and Indian lands pursuant to the Mineral Leasing Act, 30 U.S.C. §§ 181— 287, the Mineral Leasing Act for Acquired Lands, 30 U.S.C. §§ 351-359, Indian leasing statutes, 25 U.S.C. §§ 396a-396g, 25 U.S.C. § 396, and the Outer Continental Shelf Lands Act, 43 U.S.C. §§ 1331-1356. These statutes require lessees to pay royalties on the value of gas production from federal and Indian leases. By statute, Interior has broad discretion to “prescribe such rules and regulations as may be necessary to carry out” the leasing provisions. 43 U.S.C. § 1334(a); 30 U.S.C. § 189; 25 U.S.C. §§ 396 and 396(d). Defendants contend that the Rule at issue is a proper exercise of this discretion and that the Secretary may decide what will be considered in calculating “value” for purposes of royalty valuation.

To begin with, this construction overlooks important limiting language in the statutes with respect to royalty value. That is, the relevant statutes limit the collection of royalties to “the value of production saved, removed or sold from the lease.” For example, under the Outer Continental Shelf Lands Act, which governs offshore leases, the MMS may grant leases obligating lessees to pay royalties on “the amount or value of production saved, removed, or sold” from the lease. 43 U.S.C. §§ 1335(a)(8); 1337(a) and 1337(b)(3). Similarly, under the Minerals Leasing Act, the MMS may grant leases conditioned on payment of royalties “in amount or value of the production removed or sold from the lease.” 30 U.S.C. § 226(b)(1)(A). This “value of production” standard is equally applicable to Indian leases. 25 U.S.C. § 396.

The longstanding interpretation of “value of production,” one recognized by Interior (at least until the present matter) and affirmed by the courts, is that it refers to the value of oil or gas at the loells. See United States v. General Petroleum, 73 F.Supp. 225, 235 (S.D.Cal.1946), affd sub nom Continental Oil Co. v. United States, 184 F.2d 802, 820 (9th Cir.1950). Thus, it is well-recognized that the government’s royalty interest is limited to the value of production at the lease or wellhead, not in value enhancements resulting from downstream activities. Marathon Oil Co. v. United States, 604 F.Supp. 1375 (D.Alaska 1985). Accordingly, the government’s royalty interest on the value of production may not include proceeds received by lessees that are attributable to matters other than gas production. Diamond Shamrock Exploration Co. v. Hodel, 853 F.2d 1159, 1165 (5th Cir.1988). Cf. Independent Petroleum, 92 F.3d at 1252. In light of these established principles, the court finds untenable MMS’ present position that it has the authority to define value to include downstream costs unrelated to production of the gas. MMS offers no reasoned basis justifying this departure in the Rule. The court finds that the Rule does not afford a sufficient explanation as to why FERC Order 636 mandates imposing these expanded duties on producers, particularly when the primary regulatory effects of that order were directed at pipelines. Rather, MMS merely asserts that the FERC order “unbundles” marketing costs and marketing costs are not deductible.

In addition to assessing whether the relevant statutes speak to the issue of royalty valuation, the court must also look to the regulations MMS interpreted in promulgating the Rule. Here again, the court must analyze the specific provisions in light of the reasoning set forth in the Rule itself, not the post hoc justifications put forward by defendants’ counsel. As noted above, MMS concedes in the Rule that the marketable condition rule does not provide the legal basis for its assertion of a duty to market downstream at no cost. See 62 Fed.Reg. 65753 (“We recognize that the obligation to place production in marketable condition is legally distinct from the issue of marketing the gas.”). Instead, MMS claims authority for the Rule by virtue of the implied covenant of gas leases and a provision of a prior regulation con cerning royalties on processed gas at 30 C.F.R. § 202.151. And, as general authority to determine transportation deductions, MMS points to several provisions of prior regulations pertaining to transportation allowances. (30 C.F.R. §§ 206.156; 206.157; 206.176; 206.177 (1996)).

As support for its position that lessees have a duty to market downstream at no cost, MMS points to a provision in the regulation dealing with royalties on processed gas. This provision provides, in relevant part, that “[a] reasonable amount of residue gas shall be allowed royalty free for operation of the processing plant, but no allowance shall be made for boosting residue gas or other expenses incidental to marketing, except as provided in 30 C.F.R. § 206.” 30 C.F.R. § 202.151. While according appropriate deference to an agency’s reasonable interpretation of its own regulations, courts must view such interpretations with skepticism when they affect contracts to which the agency is a party. Transohio Sav. Bank v. Director, Office of Thrift Supervision, 967 F.2d 598, 614 (D.C.Cir.1992); see also Mesa Air Group, Inc. v. Department of Transportation, 87 F.3d 498, 505-506 (D.C.Cir.1996) (noting that principle of contra proferen-tem would compel finding that Department of Transportation’s interpretation of its own agreements provided “no logical stopping point” and was therefore unreasonable). As authority for the imposition of a broad-reaching duty to market gas-production at no cost, the court finds MMS’ reliance on this single provision, read out of context, to be unpersuasive. Quite simply, the court finds it unreasonable to infer a duty of general applicability from an isolated provision pertaining to production costs for processed residue gas. Moreover, the regulation itself demonstrates that it is intended as an application of the general duty to place gas into marketable condition, a duty which involves production-related activities at the wellhead. Boosting is a process that restores pressure lost during manufacturing. This restored pressure puts the gas into a condition where it can be delivered to a purchaser. Thus, as MMS concedes in its comments in the 1988 regulations, boosting and other incidental marketing expenses referred to in this provision are costs associated with placing gas in marketable condition, an obligation that is “legally distinct” from the duty to market gas at no cost. See 53 Fed.Reg. at 1236 (stating that “the cost for boosting residue gas is considered as a cost necessary to place the gas in marketable condition”). Finally, MMS’ assertions regarding this provision are undermined by the fact that the provision plainly suggests the opposite conclusion than the one MMS advances. Specifically, the provision’s concluding restrictive clause, which provides “except as provided in 30 C.F.R. Part 206,” would be superfluous if marketing costs were not otherwise deductible. See 30 C.F.R. § 202.151. In sum, the court finds that MMS’ reading of this provision, in isolation and out of context presents an unreasonable interpretation of the regulation. MMS fails to articulate a rational basis as to why a duty to market downstream at no cost flows naturally from a provision that, on its face, deals only with placing the gas in marketable condition (a production-related duty) and which suggests that marketing costs may be allowed under the regulations. Moreover, this conclusion is buttressed by reference to the regulations as a whole, which set forth extensive detail concerning the duties of lessees with respect to royalties. Given the level of detail in the regulations, one would expect them to make more than a cryptic, oblique reference to create such a far-reaching obligation.

The court also finds that MMS’ distinctions between what it now labels as “marketing” costs and “transportation” costs are not reasonably suggested by the text of the provisions governing allowances. Moreover, the arbitrary distinctions that MMS draws between the two costs result in inconsistencies, which MMS fails to explain in the Rule. Cf. Independent Petroleum v. Babbitt, 92 F.3d at 1260. For ex ample, under the Rule, MMS permits an allowance for intra-hub wheeling costs, reasoning that such costs are “actual” costs of transportation. At the same time, however, MMS rejects the deductibility of intra-hub transfer fees on the basis that they are not “actual” costs, merely “administrative” costs of transportation. Similarly, MMS provides no reasoned basis— aside from conclusory statements — for disallowing aggregator/marketer fees. 62 Fed.Reg. 65759, 67762-64. Aggregation of gas from multiple leases at a specific place and time directly implicates the movement of multiple gas streams. Yet MMS provides no explanation of why it does not consider such costs to be actual, reasonable costs of transporting gas. MMS also disallows a deduction for firm demand charges for unused capacity, stating that it does not “consider the amount paid for unused capacity as a transportation cost.” 62 Fed.Reg. 65757. MMS simply asserts that because this portion of capacity was not ultimately used to move the gas, it is not an “actual” cost of transporting gas.

By comparison, the Rule maintains allowances for other costs under the umbrella of “transportation costs,” even though these costs do not involve moving the gas. For instance, Gas Research Institute fees are required to be paid to that entity to fund research on issues pertinent to the gas industry. Likewise, Annual Charge Adjustment fees are administrative in nature, and yet are still deductible. And, finally, under the Rule storage fees for holding gas more than 30 days remain deductible, while gas held for 30 days or less is not deductible. In short, MMS simply labels certain costs marketing and certain costs transportation, without offering any consistent or principled justification for why a particular label applies.

In addition to prior regulations, MMS also premises its disallowance of downstream marketing cost deductions on an implied covenant of the gas leases. Specifically, MMS maintains that, under the leases, lessees have an implied duty to market gas at no cost to the lessor. See 62 Fed.Reg. 65756 (claiming that implied covenant of lease “dictate[s] that lessees must market production at no cost to the lessor”). MMS reasons that, by virtue of this covenant, marketing costs have always been borne by lessees, so that requiring lessees to bear these costs in downstream markets does not effect a substantive change of the lessees obligations under the leases. See 62 Fed.Reg. 65760 (stating that MMS does not have express statutory authority to implement a retroactive effective date for this rule but contending that MMS “disagree[s] that this is a substantive rule that changes or increases our existing authority and policies”). As such, MMS contends that the new language in the Rule creating an express duty to market at no cost merely clarifies the concept already embodied in “the implied covenant to market for the mutual benefit of Federal and Indian oil and gas lessees and lessors.” 62 Fed. Reg. 65756. Thus, MMS invites the court to review the leases.

In certain instances, an agency’s interpretation of contracts may be entitled to deference. See, e.g., National Fuel Gas Supply Corp. v. FERC, 811 F.2d 1563, 1570 (D.C.Cir.1987). But to be valid, such interpretations must be reasonable. Moreover, deference to an agency interpretation of a contract may be inappropriate where an agency has a proprietary interest in the contract. Lockheed Martin IR Imaging Sys. Inc. v. West, 108 F.3d 319, 322 (Fed.Cir.1997); Mesa Air Group Inc. v. Dep’t of Transp., 87 F.3d 498, 508 (D.C.Cir.1996). And, where the government drafts the terms of the contract, on a take-it-or-leave-it basis, the terms of such contracts will be construed strictly against the drafter. See, e.g., Leo Sheep Co. v. United States, 440 U.S. 668, 668, 99 S.Ct. 1403, 59 L.Ed.2d 677 (1979) (declining to find an implied easement in favor of the government when not explicitly provided for in railroad land grants).

The court begins by noting its skepticism as to the existence of an implied covenant to market at no cost in the leases, for if such an implied duty were so widely recognized and longstanding, common sense suggests that there would be no need to write it in at this late date. Indeed, MMS’ recognition that costs now disallowed by the Rule were previously being deducted by producers undercuts its assertion that producers have always been aware that such costs were not allowable by virtue of an implied covenant in the leases. Moreover, the court hesitates to endorse an agency’s proffered interpretation of a contract in which it has a proprietary interest, particularly where, as here, the interpretation greatly expands the obligations of the private party to the direct benefit of the government.

The court has reviewed the express terms of various federal and Indian gas lease forms and finds that they do not support MMS’ contention that federal gas leases contain an implied covenant to market gas at no cost. Moreover, MMS has failed to direct the court to any language or particular provision in the lease forms that supports its position that a duty to market at no cost was contemplated by the parties at the time of execution of the leases. To the contrary, the court finds that the express terms of the leases lead to the opposite conclusion by imposing certain affirmative duties on lessee and reserving correlative rights in the lessor. Quite simply, a duty to market gas at no cost may not be reasonably implied from the four corners of the lease agreements.

For example, Form 5-157, issued for oil and gas mining on tribal Indian lands, repeats the statutory mandate that royalties are to be calculated on the basis of the value of production. Form 5-157(c), at 2. In addition, the lease creates a number of express duties on the lessees, which include the duty “to exercise reasonable diligence in drilling and operating wells for oil and gas on the lands covered hereby” and “to carry out at the expense of the lessee all reasonable orders and requirements of the oil and gas supervisor relative to prevention of waste, and preservation of property and the health and safety of workmen.” Id. (emphasis added). The court finds that these two provisions do not support MMS’ position with respect to an implied duty to market at no cost. Rather, lessees’ duty to assume all costs in this provision is limited to costs related to waste prevention and health and safety, and makes no suggestion of a similar duty to market. In addition, the duty of diligence is framed in terms of production related matters, such as drilling and well operation, not sales or marketing. Given the express language of the lease form, clearly spelling out the obligations of the lessee, the court declines to imply an additional duty not expressly stated or even suggested by the actual terms of the agreement.

Similarly, Form 154h, another lease form covering allotted Indian lands, also limits the applicable royalty value, stating that “ ‘value’ for the purposes [of royalties] may, in the discretion of the Secretary, be calculated on the basis of the highest price paid or offered at the time of production .... ” Form 154h(c). This lease form also enumerates lessees’ duties to include “diligence in drilling and operating wells” and “to carry out at the expense of the lessee all reasonable orders and requirements ... relative to prevention of waste, and preservation of property and the health and safety of workmen.” Form 154h(f). These duties on the lessee are mirrored in the form’s language regarding rights of the lessor, which reserve to the Secretary the power to impose restrictions “as to time or times for drilling of wells and as to the production from any well ... when in his judgment such action may be necessary or proper for the protection of natural resources of the leased land.” Form 154h(9).

Form 436A, a lease form for oil and gas leases on federal lands, imposes a number of express duties on the lessee, but the court finds that this form fails to include any textual support for a broad-based duty to market at no cost. Form 436A(3). Notably, the express duties imposed on lessees concern operations at the well, such as drilling and production. There is no mention of obligations relating to sale or marketing. And, with respect to lessee’s royalty obligations, the form provides, inter alia, that “in no event may ‘value’ for the purposes of this lease be less than the fair market value of the production.” Form 436A(C) (emphasis added).

The court also cannot find support for an implied covenant to market at no cost in another gas lease form for lands covered by the Mineral Leasing Act, Form 3100-11. This form begins by stating that the lease may be subject to future laws and regulations “when not inconsistent with lease rights granted or specific provisions of this lease.” Form 3100-11. The lease goes on to provide that royalties “shall be computed in accordance with regulations on production removed or sold.” Form 3100-11 at Sec. 2. Section 4 of the lease obligates lessee “to exercise reasonable diligence in developing and producing, and shall prevent unnecessary damage to the loss of or waste of leased resources.” The lease also imposes certain recordkeeping obligations on lessees. Form 3100-11 at Sec. 5.

Similarly, the court finds that Outer Continental Shelf Lands Act lease forms also do not contain terms or obligations that support an implied covenant to market at no cost. To begin with, Form 3380-1 opens with a preamble which states that the lease shall be subject to “all lawful and reasonable regulations of the Secretary of the Interior when not inconsistent with any express and specific provisions herein.” The form then goes on to provide that lessee have the obligation to pay “royalty on production,” in the “amount or value of production saved, removed or sold from the leased area.” In addition, the OCSLA forms impose express duties on the lessee regarding operation of the wells. Thus, like the Indian lease forms, the OCSLA forms impose a duty of diligence concerning “drilling and producing.” While the OCSLA forms do provide that the Secretary may establish “reasonable minimum values for purposes of computing royalty on products obtained from the lease,” the same provision interjects the statutory limitation “value of production.” Moreover, the section addressing “Reservations to the Lessor,” contains a corollary provision entitled “taking of royalties,” which expressly limits royalties to “the amount or value of production.”

In sum, having reviewed the applicable lease forms, the court finds no reasonable support for MMS’ position that the leases obligate lessees to market gas at no cost to the lessor. To the contrary, the lease forms enumerate the various production- and royalty-related duties and rights without any mention of marketing or sale of gas beyond the lease or wellhead. Had the parties contemplated such an expanded duty when the contract was formed, it is likely that they would have expressly addressed it in the leases. Here, the doctrine of contra proferentem

puts the risk of ambiguity, lack of clarity, and absence of proper warning on the drafting party which could have forestalled the controversy; it pushes the drafters toward improving contractual forms; and its saves contractors from hidden traps not of their own making.

Sturm v. United States, 190 Ct.Cl. 691, 421 F.2d 723, 727 (1970). Thus, having examined the terms of the lease forms, the court finds that a duty to market at no cost does not rise by natural implication from these agreements.

Nor can MMS rely on the fact that the lease forms provide that the leases shall be subject to future regulations. Rather, in so providing, the lease forms uniformly limit the application of future regulations to those that are consistent with the express terms of the lease or that do not alter the rate of royalty. As explained above, the court finds that an implied duty to market downstream is not consistent with the terms of the existing leases.

As the Court of Appeals for the District of Columbia Circuit has instructed, deference to an agency’s interpretation is dangerous where it abrogates existing contracts and leads “a court to endorse self-serving views that an agency might offer in post hoc reinterpretation of its contract[s].” Transohio, 967 F.2d at 614. The present matter warrants this court’s apprehension. Quite simply, upholding the Rule by endorsing MMS’ interpretation of the leases and regulations would place no logical limits on MMS’ authority to rewrite the leases to the detriment of the lessees and the direct pecuniary benefit of the government. Cf. Mesa Air Group, 87 F.3d at 505-06.

III. CONCLUSION

For the reasons set forth above, the court hereby finds that the Rule amending the regulations governing royalty valuation on federal and Indian gas leases, to the extent that it imposes a duty on lessees to market gas downstream at no cost to the lessor and disallows the deduction of downstream “marketing” costs, is invalid. Likewise, the court finds that the application of the Rule to leases executed prior to the regulation is improper, as it contravenes the rights and obligations of set forth in the express terms of the leases.

A separate opinion shall issue this date.

ORDER AND FINAL JUDGMENT

Upon consideration of plaintiff American Petroleum Institute’s and plaintiff Independent Petroleum Association of America’s motions for summary judgment, defendants’ cross-motion for summary judgment, the oppositions thereto, the record and the relevant law, and for the reasons set forth in the memorandum opinion issued today, it is hereby

ORDERED that plaintiffs’ motions for summary judgment are GRANTED. The court hereby declares that the following regulations are unlawful and of no force or effect: 30 C.F.R. §§ 206.152©; 206.153®; 206.157(f)(1); 206.157(g)(2); 206.157(g)(4); 206.157(g)(5); 206.172®; 206.173©; 206.177(f)(1); 206.177(g)(2); 206.177(g)(4); and 206.177(g)(5); and it is further

ORDERED that defendants are enjoined from implementing or enforcing the above-referenced regulations; and it is further

ORDERED that defendants’ motion for summary judgment is DENIED.

Final Judgment is hereby entered for plaintiffs.

SO ORDERED.

1 . To obtain firm transportation capacity on an interstate natural gas pipeline, a lessee must reserve the capacity and pay a reservation or so-called ''demand” charge. This charge must be paid to the pipeline regardless of whether the lessee actually uses the reserved capacity. Under the proposed Rule, the deductible portion of these charges would be limited to the applicable rate multiplied by the actual volumes transported. NOPR Sections 206.157(f)(1).

2 . Intra-hub title transfer fees are paid to operators of gas pipeline hubs for services relating to accounting for the sale of gas at the hub.

3 . Commodity charges are fees assessed by pipelines to cover the variable costs of pipeline operation.

4 . Wheeling costs are fees charged by a hub operator to move gas through a market center or hub.