Fina Oil and Chemical Co. v. Norton

MEMORANDUM OPINION KENNEDY, District Judge. This case concerns a dispute over the proper method of valuing gas resources for the purpose of determining the amount of royalty payments owed to the United States government. Fina Oil and Chemical Company (“FOCC”) and Petrofina Delaware, Inc. (“PDI”) (collectively “Fina”) claim that a determination by the Department of Interior (“DOI” or “Interior” or “Agency”) regarding Fina’s required royalty payments was arbitrary, capricious, an abuse of discretion and otherwise not in accordance with the law in violation of the Administrative Procedure Act (“APA”), 5 U.S.C. § 551, et seq. Before the court are the parties’ cross-motions for summary judgment. Upon consideration of the parties’ motions, the opposition thereto, and the record in this case, the court concludes that Interior’s motion for summary judgment should be granted and that Fina’s motion for summary judgment should be denied. I. STATUTORY AND REGULATORY BACKGROUND Congress has authorized the Department of the Interior to issue and administer leases for the production of oil and gas resources pursuant to the Mineral Leasing Act, 30 U.S.C. §§ 181-287, the Mineral *248 Leasing Act for Acquired Lands, 30 U.S.C. §§ 351-359, Indian leasing statutes — 25 U.S.C. §§ 396a-396g and 25 U.S.C. § 396' — and the Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. §§ 1331-1356. These statutes require entities that enter into leases with the United States to pay royalties on the oil and gas produced from the lease. A lessee’s royalty payment is a specified percentage of the “amount or value of production removed or sold from the lease.” 30 U.S.C. § 226. The Federal Oil and Gas Royalty Management Act (FOGRMA), 30 U.S.C. § 1701 et seq., authorizes the Secretary of the Interi- or to promulgate regulations governing the management and collection of royalties. Interior has delegated the job of collecting royalties to the Minerals Management Service (MMS), a subagency within the department, which has promulgated a series of regulations governing the value of natural gas produced by a lessee. The regulations provide several methods for calculating the value of natural gas depending on the nature of the sale of the gas from the lessee to the purchaser. Under the first valuation method, if a lessee produces gas which it then sells to a purchaser pursuant to an arm’s-length transaction, the “value of gas sold under an arm’s-length contract is the gross proceeds accruing to a lessee .... ” 30 C.F.R. § 206.152(b)(l)(i). The term “gross proceeds” is defined as “the total monies and other consideration accruing to an oil and gas lessee for the disposition of the gas ....” 30 C.F.R. § 206.151. This method is known as the “gross proceeds rule.” While the regulations rely primarily on the marketplace to establish the value of production, Interior recognized that not all gas sales are made pursuant to arm’s-length transactions. Many natural gas producers have wholly-owned or partially-owned affiliates to which they sell gas. According to the regulations, arm’s-length contracts are limited to contracts between non-affiliated parties. See 30 C.F.R. § 206.151 (defining “arm’s-length contract” as a contract “between independent, non-affiliated persons with opposing economic interests regarding the contract”). Thus, by definition, transactions between two affiliated companies, such as a parent and its wholly-owned subsidiary, are non-arm’s-length transactions. Because non-arm’s-length contract prices may not represent true market value, the regulations provide an alternative method for calculating value when gas is not sold at arm’s length. See 30 C.F.R. § 206.152(c). For non-arm’s-length sales, value is determined according to the first applicable of three prioritized valuation methods, or benchmarks. The benchmarks are prioritized in the sense that if the first benchmark is found applicable it is used to calculate value without considering the other two benchmarks. If the first benchmark is not applicable then the second benchmark is used, unless it is also inapplicable, in which case the third benchmark is used. The regulations also make clear, however, that a lessee’s gross proceeds are always relevant, even when a lessee sells gas under a non-arm’s-length contract. Regardless of the method of valuation used, “under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for lease production, less applicable allowances.” 30 C.F.R. § 206.152(h). Thus, if a benchmark-derived value is lower than a lessee’s gross proceeds, the lessee’s gross proceeds will be used for royalty purposes. See Further Notice of Proposed Rulemaking, Revision of Oil Product Valuation Regulations and Related Topics, 52 Fed.Reg. 30,826, 30,843-44 (Aug. 17, 1987) (discussing identical language in oil royalty regulations). *249 In determining the lessee’s gross proceeds several costs and benefits are considered. For example, the regulations specify that [T]he lessee is required to place gas in marketable condition 1 at no cost to the Federal Government or Indian lessor unless otherwise provided in the lease agreement. Where the value established pursuant to 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 cost of which ordinarily is the responsibility of the lessee to place the gas in marketable condition. 30 C.F.R. § 206.152® (1988). 2 Thus, if the sale price received by the lessee is reduced because the purchaser is performing services to place gas in marketable condition, the value of the services performed by the purchaser is added to the lessee’s gross proceeds in order to determine the value of the gas for royalty purposes. In other words, there are certain services the value of which a lessee may not deduct when calculating its gross proceeds. For example, suppose a lessee sells non-marketable gas to another company for $20, and that company, among other tasks, purifies the gas for market and then turns around and sells it for $25, where the purification services increased the value of the gas by $3. The lessee’s gross proceeds are $23: $20 from the sale of the gas plus $3 consideration for the purification services performed by the buyer but which were not reflected in the sale price paid by the buyer. In the above example, by reducing the contract price, the lessee in effect pays a “purification fee” to the buyer in exchange for the buyer agreeing to perform duties that otherwise would be performed by the lessee. These services, even if not reflected explicitly in the contract price between a lessee and a purchaser, will be incorporated into the determination of a lessee’s royalty obligation. The regulations also identify explicitly the costs that lessees may deduct when valuing gas for royalty purposes. Lessees may deduct the costs of transporting gas to distant markets, and also may deduct certain costs related to processing gas. See 30 C.F.R. §§ 206.156, 206.157 (transportation); 30 C.F.R. §§ 206.158, 206.159 (processing). If a lessee produces gas in Colorado pays $5 to move it to Indiana where it sells the gas for $25, the value of the gas, for royalty purposes, is $20. II. FACTUAL BACKGROUND AND PROCEDURAL HISTORY Both FOCC and PDI are affiliated companies that lease natural gas rights from the United States. FNGC is an affiliate of Fina that purchases gas produced by Fina as well as other non-affiliated companies. Prior to 1990, Fina produced gas and sold it directly to purchasers. These sales typi- *250 eally took place at the point of production or “wellhead.” In 1990, FNGC was formed as an affiliate of Fina. Fina then stopped selling some of its gas directly to unaffiliated purchasers and began selling it to FNGC, which acted as a middleman by turning around and selling that gas to end-purchasers. In 1992, MMS conducted an audit of Fina’s royalty payments for gas produced at the “High Island Block 571” wellhead. MMS determined that Fina was selling gas to FNGC at a non-arm’s-length price and that FNGC was reselling the gas at a higher price. MMS also found that Fina’s royalty payments were based on benchmark values derived from its non-arm’s-length sale price to FNGC rather than on the gross proceeds accruing from FNGC’s arm’s-length sale to third-party purchasers. On September 29, 1992, MMS ordered Fina to base its royalties on FNGC’s ann’s-length contracts because MMS considered FNGC to be a marketing affiliate of Fina. See 30 C.F.R. § 206.152(b)(l)(i) (valuing a lessee’s sales to marketing affiliates according to the marketing affiliate’s gross proceeds). MMS later withdrew that order after it determined that FNGC was not a marketing affiliate under the regulations because it did not buy gas exclusively from Fina. See 30 C.F.R. § 206.151 (defining “marketing affiliate”). However, MMS expanded the scope of its audit to cover all transactions between Fina and its affiliate. On May 3, 1993, MMS issued a new order, stating that Fina’s royalty payments should be derived from the gross proceeds of FNGC’s arm’s-length sales to unaffiliated purchasers because those sale prices best reflected the value of the gas. Fina appealed the MMS order. The Agency denied Fina’s appeal on June 7,1996. Fina subsequently appealed the Agency’s 1996 ruling to the Interior Board of Land Appeals (IBLA) on August 12, 1996. Fina argued that because its sales to FNGC were non-arm’s-length transactions, the value of the gas for royalty purposes should be determined according to the system of prioritized benchmarks established by the regulations. MMS’s position was that the value of the gas was the price received by FNGC pursuant to its arm’s-length sales. According to MMS, had Fina sold its gas directly to unaffiliated purchasers, it would have charged the same higher price charged by FNGC rather than the lower sale price contained in the contract between Fina and FNGC. On June 11, 1999, the IBLA rejected Fina’s appeal. The IBLA ruled that it was bound by the Board’s decision in Texaco Exploration and Production, Inc., Docket No. MMS-92-0306-0 & G [hereinafter Texaco], which considered issues identical to those presented by Fina on appeal. In Texaco, Texaco Producing, a lessee of federal oil and gas leases, sold its oil production to its affiliate, Texaco Marketing, which then resold the oil at a higher price to arm’s-length purchasers after conducting certain marketing activities. The issue in that case was whether the value of Texaco’s oil should be determined according to the prioritized benchmarks or according to the gross proceeds resulting from the affiliate’s arm’s-length resale. In Texaco, the Acting Assistant Secretary for the Department of the Interior, with a concurrence from Secretary Babbitt, ruled that the lessee’s royalties should be based on the affiliate’s resale price rather than on a benchmark-derived value, in part because the price differential between the two values represented a marketing fee that could not be excluded from Texaco’s gross proceeds. The IBLA adopted the reasoning in Texaco as its own and denied Fina’s appeal. See Fina Oil & Chem. Co., 149 IBLA 168, 186 (1999) (“With the Secretary’s concurrence, the Texaco decision constitutes a final decision for the Depart *251 ment. See 43 C.F.R. § 4.5(a). We therefore append the Texaco decision, and adopt the analysis and rational [sic] contained therein to affirm MMS.”). This suit followed. III. STANDARD OF REVIEW Final agency action is judicially reviewable under section 704 of the APA. The IBLA’s June 11, 1999 decision is a final agency action for purposes of this suit. See 5 U.S.C. § 704. Under the APA, a reviewing court shall set aside agency action it finds to be “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with the law.” 5 U.S.C. § 706(2)(A). An agency decision is arbitrary and capricious if the agency has relied on factors which Congress has not intended it to consider, entirely failed to consider an important aspect of the problem, offered an explanation for its decision that runs counter to the evidence before the agency, or is so implausible that it could not be ascribed to a difference in view or the product of agency expertise. Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43, 103 S.Ct. 2856, 77 L.Ed.2d 443 (1983). The court’s scope of review is narrow, as it “is not empowered to substitute its judgment for that of the agency.” Citizens to Preserve Ovetion Park v. Volpe, 401 U.S. 402, 415-16, 91 S.Ct. 814, 28 L.Ed.2d 136 (1971). Although the court must still conduct “a thorough, probing, in-depth review” of the agency’s decision, see id., agency actions are presumed to be valid. See Ethyl Corp. v. EPA, 541 F.2d 1, 31 (D.C.Cir.1976) (en banc). As long as an agency considers relevant factors and can articulate a rational connection between the facts found and the choices made, its decision will be upheld. See State Farm, 463 U.S. at 43, 103 S.Ct. 2856; Marsh v. Oregon Natural Res. Council, 490 U.S. 360, 378, 109 S.Ct. 1851, 104 L.Ed.2d 377 (1989) (holding that agency action will not be reversed absent a clear error of judgment). Even greater deference is appropriate when a court reviews an agency’s interpretation of its own regulations. See Thomas Jefferson Univ. v. Shalala, 512 U.S. 504, 512, 114 S.Ct. 2381, 129 L.Ed.2d 405 (1994). The “agency’s interpretation must be given ‘controlling weight unless it is plainly erroneous or inconsistent with the regulation.’ In other words, we must defer to the Secretary’s interpretation unless an ‘alternative reading is compelled by the regulation’s plain language or by other indications of the Secretary’s intent at the time of the regulation’s promulgation.’” Id. (internal citations omitted). 3 IV. ANALYSIS The central issue in this case concerns the appropriate method of valuing gas produced by a lessee for purposes of determining the lessee’s royalty obligations. Fina argues that the relevant royalty regulations state that gas sold under a non-arm’s-length transaction to an affiliate that is not a marketing affiliate must be valued according to the prioritized benchmarks. According to Fina, the regulations do not authorize a value determination based on the gross proceeds received by the arm’s-length resale of gas by a lessee’s affiliate. Fina also asserts that it does not have to account for the marketing services performed by its affiliate when determining the value of the gas for royalty purposes. *252 Interior, following the reasoning of the Texaco decision that was subsequently-adopted by the IBLA in its adjudication of this case, argues that it is authorized to consider the arm’s-length resale price obtained by a lessee’s affiliate when determining the lessee’s royalty obligations. The IBLA provided two distinct, but related, justifications for its final decision. 4 The IBLA based its final decision, in part, on the proposition that a lessee’s gross proceeds constitute the minimum value for royalty purposes and that Fina’s gross proceeds include both its sale price to FNGC and the value of FNGC’s marketing services. In its decision, the IBLA concluded that Fina must account for FNGC’s marketing services because Fina has a duty to market the gas it produces for the mutual benefit of the lessee and the lessor at no cost to the lessor. In other words, if FNGC sells gas for a higher price than what it paid Fina because it performed additional marketing services, the associated increased in value must be reflected in Fina’s royalty payment. Thus, the IBLA concluded that by accepting a reduced sale price from FNGC in exchange for FNGC’s agreement to create a market for the gas away from the wellhead (“downstream”), Fina paid FNGC a “marketing fee” that was improperly deducted from its royalty, calculations. The IBLA also concluded that the price differential between Fina’s sales to FNGC and FNGC’s sales to unaffiliated purchasers was due to FNGC’s downstream marketing efforts, and that as a result, the actual gross proceeds accruing to Fina were Fina’s sale price to FNGC plus the value of FNGC’s marketing efforts, which equal FNGC’s arm’s-length resale price. Fina claims that Interior’s position that the difference between its sale price to FNGC and FNGC arm’s length resale price represents marketing services upon which Fina must pay royalties is arbitrary and capricious for three reasons. First, Fina argues that it does not have to include FNGC’s marketing costs in its royalty payment because neither the regulations nor the lease impose a duty on Fina to market its production. In the alternative, Fina contends that even if it is obliged to market gas, that obligation does not extend to downstream marketing services. Second, Fina asserts that the price differential between its sale to FNGC and FNGC’s arm’s-length resale includes services other than marketing services. Thus, Fina claims that FNGC’s resale price does not represent Fina’s gross proceeds, even if marketing services are included in the gross proceeds calculation. Third, Fina argues that Interior is barred from seeking to collect royalties because the statute of limitations has run. Fina’s arguments cannot be sustained. A. The Duty to Market Gas The value of the gas upon which a lessee pays royalties can never be less than the lessee’s gross proceeds. See 30 C.F.R. § 206.152(h). The question in this case is whether Interior acted in an arbitrary and capricious manner in concluding that the gross proceeds accruing to Fina include any increase in value resulting from marketing services performed by the its affiliate is reasonable. Answering that question requires the court to determine whether Fina’s lease or federal regulations impose a duty on Fina to perform downstream marketing services. The court holds that Interior articulated a rational basis for its decision that they do impose such a duty and for its ensuing determination that *253 Fina’s royalty payments should be based on the prices received by FNGC in its arm’s-length sales. A lessee’s royalty obligation under a federal lease is governed both by contract and by regulation. Oil and gas leases are contracts, and therefore contract principles aid in their interpretation. See Phillips Petroleum Co. v. Lujan, 4 F.3d 858, 860 n. 1 (10th Cir.1993) (“Both parties recognize and we agree, that oil and gas leases are contracts.”) (citing Reese Exploration v. Williams Natural Gas, 983 F.2d 1514, 1518-19 (10th Cir.1993)). To interpret a contract, the context and intent of the contracting parties must be considered. See Metric Constructors, Inc. v. NASA, 169 F.3d 747, 752 (Fed.Cir.1999). Evidence of trade practice and custom can provide meaning and clarity to contract terms by shedding light on the parties’ intent. See id. at 752-53. A lessee’s royalty responsibility is also governed by regulation. This is especially true when interpreting federal leases, because the standard federal lease incorporates and gives controlling weight to Department of Interior regulations. 5 See Indep. Petroleum Ass’n of Am. v. DeWitt, 279 F.3d 1036, 1037 (D.C.Cir.2002). The regulations state that the value of the gas produced can never be less than the lessee’s gross proceeds, and also detail which costs a lessee may deduct when determining the value of the gas it produces. Thus, to properly interpret Fina’s leases, the court must harmonize principles of contract construction with federal regulations. It was neither arbitrary nor capricious for the Agency to conclude that Fina has some implied duty to market - the gas it produces. A lessor’s decision to lease gas resources is based upon the expectation of receiving a royalty from the lessee’s sale of the gas. If the lessee does not market its production for purchase, then there is no royalty to be realized. Thus, by agreeing to lease gas resources, the lessee implicitly agrees to market the gas for sale. See Martin v. Glass, 571 F.Supp. 1406, 1415-16 (N.D.Tex.1983); 3 Kuntz, Law of Oil and Gas, § 40.5 (1989); 2 Summers, Oil and Gas, § 415 p. 631 (1959). Federal courts have recognized that lessees have a duty to place gas in marketable condition for more than forty years. See California Co. v. Udall, 296 F.2d 384, 387 (D.C.Cir. 1961). Thus, Fina has a duty to market for sale the gas it produces. Fina claims that even if it does have a duty to market gas, that duty does not encompass downstream marketing services performed by its affiliate. Fina’s claim must be rejected. The D.C. Circuit recently addressed a similar question regarding whether Interior could require oil and gas lessees to pay royalties on their downstream marketing costs in Independent Petroleum Ass’n of America v. DeWitt, 279 F.3d 1036 (D.C.Cir.2002). DeWitt involved a challenge to a 1997 amendment to the federal royalty regulations that, inter alia, altered the “marketable condition” rule. See id. Prior to 1997, the marketable condition rule stated that the services performed by lessees to place gas in marketable condition must be included as part of gross proceeds. Interior changed the marketable condition rule in 1997, adding that lessees have a duty to market gas at no cost to the lessor in addition to their duty to place gas in marketable condition. See 62 Fed.Reg. 65,753 (Dec. 16, 1997); 30 C.F.R. § 206.152®. *254 An association of oil producers challenged the regulation, arguing that the Agency had no rational basis for including downstream marketing services as part of gross proceeds. The D.C. Circuit upheld the amended regulation, holding that it was not unreasonable for Interior to require gas producers to make marketing services non-deductible. In upholding the regulations, the court, citing several past IBLA decisions, observed that marketing services traditionally have not been deductible from gross proceeds, and noted that the only allowable deductions have been for the costs of transporting and processing gas. See DeWitt, 279 F.3d at 1037-38 (citing Walter Oil & Gas Corp., Ill IBLA 260, 265 (1989), and Arco Oil & Gas Co., 112 IBLA 8, 10-11 (1989)). The court also stated that Interior has repeatedly distinguished between transportation services and marketing services in deciding what lessees can deduct from gross proceeds, and ruled that the new regulation merely reflects that longstanding distinction. See id. at 1041. The court further noted that the plaintiffs position that all value-added activities taking place away from the wellhead should be deductible — which is virtually identical to Fina’s position in this case — would eviscerate any distinction between marketing and transportation and would render superfluous the regulations that specifically allow deductions for the cost of transporting gas away from the wellhead. See id. Additionally, the court emphasized that producers cannot deduct marketing costs performed at the wellhead, and held that those same costs should not become deductible simply by virtue of being performed at a different location. See id. at 1040-41 (“a change in the dimension of a cost is hardly an argument for its reclassification”). While the Circuit’s decision in DeWitt addressed a regulation not at issue here and therefore does not control the outcome of this case, the Circuit’s reasoning persuades the court that Interior did not act unreasonably in ordering Fina to include FNGC’s downstream marketing services when calculating gross proceeds. As the DeWitt court pointed out, it is the nature of the cost — i.e. whether it is a transportation cost, processing cost, or marketing cost — that, determines whether it is deductible, not where or by whom that cost is incurred. Since the services performed by FNGC would be included as part of Fina’s gross proceeds if they were performed at or near the lease, they should also be included even though they were performed away from the lease. The regulations already allow deductions for specific downstream services, such as transportation, and thereby account for the fact that markets for gas exist away from the wellhead. See DeWitt, 279 F.3d at 1041 (observing that the plaintiffs position that all downstream services should be deductible “condemnfs] any distinction between marketing and transportation.”). Unlike transportation, however, which need only be performed if gas is to leave the wellhead, the marketing services a lessee typically performs at the wellhead are similar to those performed away from the wellhead. See DeWitt, 279 F.3d at 1040-41. As a result, there is no reason why a service should be deductible just because it is performed away from the wellhead, and Interior acted rationally in deciding that Fina must include downstream marketing services in its gross proceeds calculation. Similarly, the irrelevance of the entity performing the services to the question of whether the services should be included in gross proceeds also provides a rational basis for the Agency’s construction of the regulations. As the Agency noted in Texaco, if the lessee had performed the marketing services itself, then the value of those services would have been included as *255 a part of gross proceeds. See Texaco, at 15. In contrast, Fina’s position would allow lessees to pay significantly fewer royalties on the same revenues simply by contracting to have an affiliate perform all downstream activities that the lessee would otherwise perform itself. Fina should not be able to escape its royalty obligations merely by transferring marketing duties to its wholly-owned affiliate. Those services that are deductible, such as transportation and processing, are deductible no matter who performs them. Thus, Interior acted reasonably in concluding that Fina cannot circumvent the royalty regulations by contracting with its affiliate to carry out marketing functions. Furthermore, as the DeWitt decision makes clear, it has been Interior’s trade practice, or custom, to refuse to allow deductions for marketing services. The Agency has held since 1989, and perhaps earlier, that a lessee’s implied duty to market production includes all marketing services. See, e.g., Walter Oil & Gas Corp., 111 IBLA 260, 265 (1989); Arco Oil & Gas Co., 112 IBLA 8, 10-11 (1989); see also DeWitt, 279 F.3d at 1041 (noting Interior’s longstanding position that marketing costs are not deductible). 6 Thus, given that the Agency had a common practice of including marketing services as part of gross proceeds, it was neither arbitrary nor capricious for Interior to determine that Fina’s implied duty under its leases to market its production includes the duty to create and develop markets for its gas. The legislative history surrounding the definition of gross proceeds further supports the Agency’s position that it is reasonable to include marketing services as part of gross proceeds. When Interior promulgated new royalty rules in 1988, it stated that the term “gross proceeds” should be construed broadly to include all consideration exchanged by the contracting parties. See Final Rule, Revision of Gas Royalty Valuation Regulations and Related Topics, 53 Fed.Reg. 1230, 1241 (Jan. 15, 1988) (“It is [the Agency’s] intent that the definition [of gross proceeds] be expansive to include all consideration flowing from the buyer to the seller for the *256 gas, whether that consideration is in the form of money or any other form of value.”); See also Arco, 112 IBLA at 11 (noting that the term “gross proceeds” has been construed broadly). The Agency noted that gross proceeds includes anything of value “from which the seller benefits” even if it is not actually paid from the buyer to the seller. Id. Furthermore, the Agency stated that lessees “cannot avoid their royalty obligations by keeping a part of their agreement outside the four corners of the contract.” Id. The definition of gross proceeds can reasonably be read to include FNGC’s marketing services. In addition to the price received from FNGC for the sale of gas, FNGC’s marketing services constituted valuable consideration as part of the transaction. Fina relieved itself of having to perform marketing services in exchange for accepting a reduced sale price from FNGC. Had Fina chosen to perform marketing services itself, it would have added value to the gas and would have been able to command a higher price than the price at which it sold the gas to FNGC. 7 In essence, Fina paid FNGC a fee to perform marketing services. Thus, Interior reasonably concluded that those services must be included as part of gross proceeds. B. FNGC’s Services are Marketing Services Fina’s argument that the difference between its sale price to FNGC and FNGC’s arm’s-length resale price is not solely attributable to marketing is also unpersuasive. Fina lists the services performed by FNGC that it claims account for the difference. Those services comprise: • aggregating gas from multiple purchasers into larger volumes so that it is more attractive to buyers; • undertaking the risks of market ' price fluctuations; • assuming tort exposure; • storing gas; • entering into swaps; • transporting gas; and • selling gas. Fina provides no reason why the services performed by FNGC, other than transportation, do not involve marketing. All the functions listed by Fina involve costs and risks associated with creating, developing and finding markets for its gas. Aggregation services, storage, handling inventory, finding purchasers, and negotiating sales contracts historically have been considered marketing costs by both courts and the IBLA. See, e.g. DeWitt, 279 F.3d at 1042 (upholding amendments to the gas royalty regulations making aggregator fees non-deductible); Seagull Energy Corp., 148 IBLA 300, 312 (1999) (“Finding purchasers, negotiating sales contracts, and monitoring sales are also the lessee’s responsibility.”); Mobil Oil Corp., 112 IBLA 198, 208-09 (1989) (holding that compression, storage and loading services are marketing services); Amoco Prod. Corp., 112 IBLA 77, 87 (1989) (finding that costs of storage, stock loss, inventory, receivables and equipment are part of marketing); Arco, 112 IBLA at 9 (finding that dealing with local distribution companies and aggregation are marketing services). Thus, Interior’s position that the regulations disallow Fina from deducting any of the services performed by FNGC from its *257 gross proceeds valuation other than transportation is neither arbitrary nor capricious. 8 Fina also argues that some of the costs which Interior claims are non-deductible, such as bearing the risk of market price fluctuations, are not actually costs, and therefore should not be included in gross proceeds. Fina asserts that if market risk were considered a cost, then the costs of marketing would change as market prices fluctuate, and notes that if market prices fell enough during a particular month, overall marketing costs would be negative. According to Fina, “[r]eal costs do not work this way.” Pl.’s Opp., at 16. Fina’s position is clever but ultimately unpersuasive. First, market risk, while perhaps not a fixed cost, is a cost nonetheless. 9 FNGC bears a specific burden by shouldering the risk of market fluctuations. Sometimes the risk will have an upside and sometimes it will have a downside, but it is FNGC that must weather the cost of confronting market uncertainty. Second, a lessee’s royalty obligation is based on the value of the gas produced at the lease, not the cost of producing the gas. See 30 U.S.C. § 226 (“A lease shall be conditioned upon the payment of 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.”) (emphasis added). If the value of gas increased because FNGC undertook certain costs, it is that increase in value that is relevant for determining royalty payments rather than the expenditures necessary to realize that higher value. 10 Because Interior’s interpretation that the difference between Fina’s sale price to FNGC and FNGC’s arm’s-length resale price is the result of marketing activities carried out by FNGC is reasonable, FNGC’s arm’s-length resale price is an appropriate value for determining Fina’s royalty obligations. C. Statute of Limitations Finally, Fina argues that any collection claim by the United States is barred by the statute of limitations. The statute of limitations governing this action is 28 U.S.C. § 2415(a), which states that any action brought by the United States for money damages founded on a contract must be filed within six years of the time the right of action accrues, or within one year of a final administrative decision. See 28 U.S.C. § 2415(a). 11 Because this case involves royalty payments from Octo *258 ber 1990 to Majr 1993, and because the final administrative decision was issued on June 11, 1999, Fina argues that the statute of limitations has run. Fina claims that if the government wanted to collect royalties from Fina, it should have filed a counterclaim against Fina. Fina’s argument is without merit. Section 2415 only bars actions brought by the United States. This action has been brought by Fina, and therefore § 2415 does not apply. See S.E.R., Jobs for Progress, Inc. v. United States, 759 F.2d 1, 5 (Fed.Cir.1985) (“[T]he challenged action is not an ‘action for money damages brought by the United States,’ as expressly required by the statute. Instead it is an administrative appeal by a contractor from a contracting officer’s decision .... Therefore, we hold that 28 U.S.C. § 2415 is inapplicable on its face.”). 12 Thus, this suit is not barred by the statute of limitations because it has been brought by Fina and not by the United States. Additionally, Fina’s argument runs contrary to the design of the statute. The purpose of Section 2415 is to prevent prejudice to parties because of dilatory or negligent behavior by government officers. See id. at 8. Here, the government has done nothing of the sort. Interior has diligently sought to collect royalties from Fina for the past nine years. It issued an order for increased royalty payments immediately upon discovering that Fina may have underpaid. Since then, Fina has fought the government every step of the way, filing one appeal after another disputing the government’s authority to collect additional royalties. The only reason that six years have .passed since Interior’s initial order is because Fina has used both the administrative and judicial process to delay payment. Fina is certainly within its rights to avail itself of these processes, but it cannot do so and then argue that the time theses processes require operate to foreclose the United States from collecting any unpaid royalties. See Mesa Operating Ltd. P’ship v. Dep’t of Interior, 17 F.3d 1288, 1291-92 (10th Cir.1994) (“Plaintiff having now lost its appeal at all levels, it would seem unjust in the extreme to permit the delay through litigation initiated by plaintiff and supported by a bond sufficient to cover the payments in the amounts claimed by defendant to give plaintiff the cover of the statute of limitations to avoid payment of the royalties”). Furthermore, Fina’s contention that the government should have sought payment by filing a counterclaim cannot be sustained. Since the subject of any counterclaim would be identical to that of the present suit, Fina’s position would only serve to waste scarce judicial resources by requiring the government to file a duplicative lawsuit. Thus, this action is not barred by the statute of limitations. V. CONCLUSION For the foregoing reasons, Fina’s motion for summary judgment must be denied and Interior’s motion for summary judg *259 ment must be granted. An appropriate order accompanies this memorandum. ORDER Pursuant to Fed.R.Civ.P. 58, and for the reasons set forth in the accompanying Memorandum Opinion, it is hereby ORDERED that the JUDGMENT is entered in favor of defendant; and it is further ORDERED that the complaint is DISMISSED. Footnotes [1] Gas products are in "marketable condition” when 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. Both parties in this case acknowledge that the gas at issue was in marketable condition. [2] Interior amended this provision in 1997 to state that the lessee not only has the duty to place the gas it produces in marketable condition, but must also "market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government.” 30 C.F.R. 206.152(i). See 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 (1997). Because the royalty payments at issue here only cover a period from 1990 to 1993, the earlier regulation applies to this action. [3] Fina argues that Interior is not entitled to deference because it has a financial interest in the lease that is the subject of the dispute. Because the court’s decision would be the same regardless of the amount of deference afforded the Agency, the court need not address Fina’s argument. [4] Because the court's memorandum opinion only addresses the question of whether a lessee can deduct its affiliate's marketing services from a royalty calculation, the merits of the IBLA's other rationale for its decision are not discussed here. [5] Because the parties failed to include Fina's leases with the federal government as part of the administrative record, the court does not know what terms are contained therein. Nei-ther party, however, has indicated that Fina's leases are different than the standard leases the United States signs with other oil and gas producers. [6] Fina argues that Interior does not have a custom of denying marketing deductions because prior to the issuance of FERC Order 636 in 1992, when lessees sold gas directly to pipelines, Interior allowed deductions for many of the marketing services it now claims are non-deductible. The only reason those services were formerly deductible, however, is that after lessees sold gas directly to pipelines, the pipelines performed a number of different “bundled” services, some of which involved transportation. Since the services were "bundled” together such that Interior could not separate a pipeline’s transportation services from its other downstream services, Interior did not include the other downstream services as part of gross proceeds. See Indep. Petroleum Ass’n of Am. v. Armstrong, 91 F.Supp.2d 117, 120 (D.D.C.2000), rev’d in part, 279 F.3d 1036 (D.C.Cir.2002); Notice of Proposed Rulemaking, Amendment to Transportation Allowance Regulations for Federal and Indian Leases to Specify Allowable Costs and Related Amendments for Gas Valuation Regulations, 61 Fed.Reg. 39,931, 39,932 (July 31, 1996). In 1992, FERC issued Order 636 requiring pipelines to “un-bundle” their services. See 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. 13,267 (Apr. 16, 1992). This enabled Interior to distinguish marketing services from transportation services more effectively. Thus, Interior did not have a past practice of allowing marketing deductions, but only allowed deductions when it could not specifically identify the marketing services performed by the pipeline. Even before FERC ordered the unbundling of pipeline services in 1992, however, Interior refused to allow marketing deductions when marketing costs were distinguishable from transportation costs. See e.g., Arco, 112 IBLA at 10-11 (disallowing deduction for services performed by a marketing agent); Walter, 111 IBLA at 265 (same). [7] The parties do not address, and the court does not reach, the question of whether Fina would have breached its duty to market if it had failed to carry out downstream marketing services and instead had chosen to sell its gas for a lower price at the wellhead. To the extent that it chose to pay FNGC to perform marketing services and therefore added value to the gas, Fina received a benefit that cannot be excluded from its gross proceeds calculation. [8] The parties do not point to any portion of the record indicating that Fina sought, and did not receive, a deduction for transportation costs. Neither party even raises the issue of a transportation deduction in their briefs before the court. It is the lessee’s burden to request a transportation allowance. See 30 C.F.R. § 206.157 (1988). [9] Presumably, FNGC's market risk could be converted to a concrete value by determining an expected market value of gas and comparing that to the sale price. [10] It is easy to see how confusion might result over the use of the term "cost.” In many cases, royalty disputes involve situations where producers want their actual costs deducted from royalty obligations rather than situations where the Agency seeks to make a producer pay extra royalties on value-added services. In the context of deductions, cost may be a more appropriate framework than value because a producer should not be able to deduct more than the cost of the service it performed. If a producer can spend $3 on transportation and increase the value of the gas by $10, there is no reason why a producer should be able to deduct $10 from its royalty payments when it only made a $3 investment. [11] In 1996, Congress enacted a seven-year statute of limitations for royalty claims brought by the federal government. See 110 Stat. 1700, 1705 (1996) (codified at 30 U.S.C. § 1724(b)(1)). Because the dispute in this case arose prior to 1996, the six-year limitations period under § 2415(a) applies. [12] Even if this action does fall within § 2415, it would still be timely, because the term "action” as used in the statute includes administrative actions. See Oxy USA, Inc. v. Babbitt, 268 F.3d 1001 (10th Cir.2001). Since the Agency brought its initial administrative action within the six-year time-frame, and since everything following has been an appeal of that initial action, the statute of limitations would not bar the present claim. Furthermore, the administrative proceedings spanning from the issuance of the Agency's initial order until the IBLA’s final decision, have tolled the limitations period. See Marathon Oil Co. v. Babbitt, 938 F.Supp. 575, 578-79 (D.Alaska 1996) ("Despite the applicability of 28 U.S.C. § 2415(a), the government’s collection action is timely because the statute was tolled during the administrative proceeding from the time the initial audit was announced ... until the announcement of the decision of the responsible agency ....”).