Mesa Operating Limited Partnership v. U.S. Department of the Interior

931 F.2d 318, 1991 WL 65527

• Court: Court of Appeals for the Fifth Circuit
• Decided: June 27, 1991
• Docket: 89-4775
• Status: Published

Opinion

JOHN R. BROWN, Circuit Judge:

The Director of the Minerals Management Service (MMS) division of the U.S. Department of the Interior (DOI) ordered Mesa Operating Limited Partnership (Mesa), which extracts natural gas from offshore leases, to pay royalties on reimbursement payments made to Mesa by pipeline company purchasers pursuant to the Natural Gas Policy Act (NGPA) § 110. 1 The DOI affirmed the MMS demand order. Mesa appealed the DOI’s decision to federal district court, contending that the DOI misinterpreted regulations governing assessment of royalties. After referring the case to a magistrate, the district court rejected Mesa’s arguments and entered summary judgment in favor of the DOI. Mesa now appeals to this court.

We hold that the DOI, in affirming the MMS order, made a permissible interpretation of the federal regulations which govern royalties owing from federal natural gas leases. We therefore affirm the district court.

I. Background

A. Statutory and Regulatory Framework

The Outer Continental Shelf Lands Act of 1953 (OCSLA) 2 authorizes the Secretary of the DOI to grant and manage leases for recovery of oil, gas, and other minerals from submerged lands located on the Outer Continental Shelf. OCSLA also vests in the Secretary the sole authority and responsibility to “prescribe such rules and regulations as may be necessary to carry out such [leasing] provisions [of OCS-LA].” 3 Since 1982, the Secretary has delegated the administrative responsibility for OCS leases to the MMS. 4

OCSLA provides that the DOI obtains royalties from lessees based on the “amount or value of the production saved, removed, or sold.” 5 The Secretary has promulgated several regulations relevant to a definition of this phrase. The first such provision, issued in 1954, provided that the “value of production” shall never “be less than the gross proceeds accruing to the lessee from the disposition of the produced substances.” 6

The Secretary promulgated a second regulation in 1954 which requires lessees to put extracted gas into “marketable condition” and to pay royalty on the marketable gas without first deducting for the costs of treatment. 7 The so-called “marketable condition rule” states:

The lessee shall put into marketable condition, if commercially feasible, all products produced from the leased land. In calculating the royalty payment, the lessee may not deduct the costs of treatment. 8

With the NGPA, 9 Congress set price ceilings for defined categories of natural gas, representing the maximum lawful consideration due the producer-seller. Congress created the Federal Energy Regulatory Commission (FERC) to administer the new act. NGPA § 110 excepts from the ceiling price regulation certain post-production costs, allowing producers to recover these costs in addition to the unit price for delivered gas from purchasers. That section provides, in relevant part:

... [A] price for the first sale of natural gas shall not be considered to exceed the maximum lawful price applicable to the first sale of such natural gas under this part if such first sale price exceeds the maximum lawful price to the extent necessary to recover—

(1) State severance taxes ...; and

(2) any costs of compressing, gathering, processing, treating, liquefying, or transporting such natural gas, or other similar costs, borne by the seller and allowed for, by rule or order, by the [FERC]. 10

FERC implemented § 110 through its Order No. 94 and supplemental orders 11 which provided that a first seller of natural gas may receive payment for “production-related costs” over and above the otherwise applicable ceiling price within the “first sale price.” 12 “Production-related costs” is defined to include “costs, other than production costs, that are incurred: (1) To deliver, compress, treat, liquefy, or condition natural gas....” 13 The amount of the reimbursements to which producer-sellers are entitled is based upon factors including the age of the pipeline gas deliv ery system and the difficulty of the treatment process, which often depends upon the quality of the gas. 14 The seller may also recoup other costs which the purchaser has expressly agreed to bear. 15

Soon after they were promulgated, various natural gas pipeline purchasers and distributors challenged the reimbursement rules in several actions which reached this Court on appeal, contending that the rules were irrational and not supported by the evidence. In a consolidated decision, Texas Eastern Transmission Corp. v. Federal Energy Regulatory Comm ’n, 16 we expressly rejected these challenges, affirming FERC’s authority pursuant to NGPA § 110 to promulgate regulations which entitle natural gas producers to reimbursement for certain production-related costs.

Following this decision, the MMS reevaluated its requirement that § 110 reimbursements be included in the “gross proceeds” amount for calculating royalties due the DOI. 17 The result, a comprehensive report entitled “Policy for Production-Related Cost Payments Under Section 110 of the [NGPA] of 1978,” 18 established that the MMS considered such payments part of the value of production and the lessees’ “gross proceeds” and reminded lessees that § 110 reimbursements are subject to royalty.

B. Factual and Procedural Details

Mesa owns interests in several mineral leases off the coasts of Louisiana and Texas which the DOI administers pursuant to OCSLA. Mesa produces natural gas from various wells located on the leased lands and sells the gas to pipeline company purchasers under long-term sales contracts. Under the leases, which incorporate all applicable federal statutes and regulations, Mesa must calculate royalty payments due the DOI equal to 16% percent of the value of “production saved, removed or sold” from the leased property, which it periodically pays through the MMS. 19

After an early 1987 audit, the MMS demanded by letter dated February 27, 1987, that Mesa pay royalties on § 110 cost reimbursements Mesa had received to date. After forwarding a letter of credit to the MMS for $1,509,529.88, the amount of “disputed” unpaid royalties as of February 1987, 20 Mesa appealed the MMS’s audit demand to the DOI.

On October 7, 1987, the DOI issued a final ruling affirming the MMS’s position that § 110 reimbursement payments which Mesa had received were royalty-bearing payments. The DOI ruling stated that the MMS policy of subjecting § 110 payments to royalty valuation was well within the “considerable discretion” accorded the Secretary “to establish for royalty purposes the value of production from Federal oil and gas leases.” 21 In its opinion, the DOI based its analysis on the Marketable Condition Rule, 22 stating that the justification for treating § 110 reimbursements as royalty-bearing payments is firmly grounded in that rule’s requirement that “the lessee must bear the costs of marketing the production.” It declined to distinguish for royalty purposes between proceeds from the sale of produced gas and § 110 reimbursements made by pipeline company purchasers. The opinion concluded:

The lessee has the duty to market the production from a Federal lease. Therefore, the marketing costs, like the production costs, do not qualify as a deduction from the lessee’s gross proceeds received.

Mesa appealed the DOI’s decision to federal district court, where Mesa and the DOI each filed cross-motions for summary judgment. The district court referred the motions to the magistrate, 23 who recommended that the DO I decision and the MMS order be upheld. Mesa argued that this Court’s recent decision in Diamond Shamrock Exploration Corp. v. Hodel, 24 in which we defined “production” as “the actual physical severance of minerals from the formation” 25 required a holding that royalty could not be levied on § 110 reimbursements for “production-related costs” incurred well after “actual production,” that is, “physical severance.” In an oral ruling, the district court confined the Diamond Shamrock definition of production to the royalty dispute over “take-or-pay” contracts at issue in that case. The court then adopted the magistrate’s report and recommendation and entered judgment for the DOI. Mesa brings this appeal.

II. Standard of Review

We review the district court’s grant of summary judgment de novo. Under the Administrative Procedure Act, however, we must not set aside the DOI’s findings unless its decision was “arbitrary, capricious, or otherwise not in accordance with law.” 26 In addition, because the determination at issue here involved the interpretation of a statute, the question for this Court is “whether the agency’s interpretation is based on a permissible construction of the statute.” 27 This standard is especially applicable where, as here, relevant statutes and regulations do not address the precise question, specifically whether § 110 payments are royalty-bearing for the benefit of the DOI-lessor. 28

Mesa contends that the DOI’s order constitutes an impermissible construction of the Gross Proceeds and Marketable Condition Rules. Section 110 payments at issue in this case should not be subject to royalty valuation under the regulations as they stood in February 1987 for three reasons: (1) the Marketable Condition Rule is irrele vant to royalty valuation of § 110 cost reimbursements; (2) the DOI’s position conflicts with the policies underlying the NGPA § 110, which Congress enacted in order to encourage producers to explore for new sources of lesser quality natural gas; and (3) this Court’s intervening decision in Diamond Shamrock prohibits the DOI’s broad construction of “value of production saved, removed, or sold,” the benchmark for royalty assessment.

III. The Merits

A. The Marketable Condition Rule

The DOI relies heavily on the Marketable Condition Rule to reach its conclusion that § 110 payments are subject to royalty valuation. In short, the DOI interprets the regulations to provide that: royalties are due on the gross proceeds accruing to the lessee; the term “gross proceeds” includes payments for the costs of treatment including measuring, gathering, compressing, sweetening, and dehydrating “where such services are necessary to place gas in marketable condition,” whether the costs are absorbed in the price the purchaser pays pursuant to the set NGPA ceiling or are ultimately borne by the purchaser under § 110; accordingly, where the purchaser reimburses the lessee for treatment costs in accordance with § 110 and the Order 94 regulations, these payments become part of the value of production (gross proceeds) subject to royalty. Mesa argues that the DOI order is unacceptable and the district court should be reversed because the regulations do not support such a construction. While Mesa’s reading of the regulations may be plausible, we may reject the DOI’s Order (and, consequently, the district court’s judgment) only if the agency’s interpretation is impermissible or unreason able: 29 Granting this deference, we con-elude that the DOI’s construction certainly does not rise to this level.

Mesa does not challenge the Marketable Condition Rule itself. 30 Rather, Mesa contends that the Rule focuses on the duty to market the gas, forbidding lessees from discontinuing or interrupting the production of gas or producing and wasting gas, 31 and has no bearing on calculation of royalties on § 110 payments. Mesa acknowledges that the Marketable Condition Rule, which prohibits lessees from deducting treatment costs incurred in complying with the Rule when figuring royalty due, has some relevance to the calculation of royalties. However, Mesa contends that the Rule prohibits producers from deducting costs of treatment from the calculated royalty amount itself rather than the royalty base against which the royalty rate is applied (that is, the total proceeds from sale on which royalty is due).

In addition, Mesa maintains that this prohibition does not translate into an affirmative obligation to pay royalties on § 110 reimbursements for treatment costs. Such a requirement, Mesa argues, would have the anomalous result of entitling the DOI to inverse recovery of greater royalties roughly proportionate to the poor quality of the gas and the difficulty of treatment.

(i) Consistent Application

A review of the historical backdrop behind § 110 appears to support the DOFs attempt to attach royalties to § 110 payments.

The Natural Gas Act of 1938 (NGA) 32 introduced cost-based price ceilings for the “sale in interstate commerce of natural gas for resale” and entrusted the administration of this price regulation to the Federal Power Commission (FPC). 33 Originally the NGA applied only to pipelines, calculating maximum prices according to actual costs plus a reasonable rate of return and depreciation. 34 In 1954 the Supreme Court expanded the ambit of the NGA to give the FPC jurisdiction over the rates charged by producers offering natural gas for first sale. 35

The FPC’s method of regulation fluctuated over its term as administrator of producer price ceilings. 36 Following the Phillips mandate, the FPC set out to fix first sale prices on an individual basis, necessitating detailed studies of the rate bases and operating costs for each producer. This procedure proved to be cumbersome, 37 and in 1960 the Commission abandoned the individual assessment procedure for area rate regulation, whereby it set producer prices for an entire geographic region based on the region’s average production, costs, and rates of return. 38 To induce producers to search for new supplies of natural gas, the FPC authorized producers to recoup extraordinary costs from purchasers where “special circumstances” called for such compensation. 39 The FPC continued to grant such special relief even after it changed its ratemaking procedure to establish a national price for natural gas. 40 This incentive was carried over into the NGPA in sections 102, 41 103, 42 107, 43 108, 44 and 110. 45

Considering this history of ceiling price regulations, it appears that the DOI is essentially correct in its assertion that it has applied the Marketable Condition Rule consistently to all “gross proceeds,” including § 110 reimbursed costs, since the Rule was promulgated in 1954. Under the NGA pricing arrangement, the FPC’s area and national rate regulation programs granted producers special relief for actual costs, a scheme similar in scope and purpose to the NGPA § 110. 46 The DOI subjected the NGA special “add-on” prices to royalty assessment. 47 Mesa has been unable to convince this Court that under the NGPA the effect should not be the same.

Mesa’s contention that the Marketable Condition Rule applies to the royalty amount itself rather than the royalty base evidences a fatal misreading of the Rule and its accepted construction, undermining much of Mesa’s argument on appeal. Its reading is indeed contrary to the interpre tation the DOI has given the Marketable Condition Rule for decades, that is, that marketing costs cannot be deducted from the gross proceeds, equal to the value of production, before royalty is calculated. 48 As the Interior Board of Land Appeals recently stated in ARCO Oil & Gas Co., 49 only such marketing allowances “as have been expressly recognized may properly be deducted from value [of production] for royalty purposes.” 50 As did the D.C. Circuit in California Co., in the context of this case we define “production” in the phrase “amount or value of the production” as meaning “gas conditioned for market.” 51

Second, any anomaly which results from allowing higher royalty on lower quality gas by assessing royalty on § 110 payments is a consequence of the NGPA/FERC price regulation system and not of the scheme setting out the royalty owner’s rights. Indeed, this is a uniform result. The DOI-lessor simply obtains a flat percentage of all “gross proceeds” whether they be within the ceiling price or exceed it under § 110, obtaining more royalty where the lessee obtains a greater price, including costs reimbursements, from the pipeline purchaser. 52

(ii) No Conflict With NGPA or FERC

Moreover, because the motives behind special relief measures such as were put forth by the FPC, and by FERC pursuant to § 110, did not change, we are unconvinced that including § 110 reimbursements in the royalty-bearing “gross proceeds” from the sale of gas necessarily thwarts Congress’ intention to provide incentives for exploration and production of low quality gas by allowing for producers to be reimbursed for certain actual costs. Knowing that the FPC had allowed royalties on special relief prices in the past, it was for Congress, if it had intended the incentive to be greater than under the NGA, to provide that NGPA § 110 payments not be subject to royalty.

Likewise, the DOI’s royalty demand presents no conflict with FERC’s Order 94 program, which this Court upheld in Texas Eastern, 53 Citing this Court’s determination in Diamond Shamrock that we would not allow the DOI’s royalty policy to interfere with FERC’s regulation of the producer-purchaser relationship in the take-or-pay situation, 54 Mesa seizes on FERC’s characterization of treatment expenses as “post-production” costs. 55 But more often FERC attaches the phrase “production-related” to these expenses, 56 and has nowhere indicated that this nomenclature affects or refers to royalty valuation. Absent plain meaning or contrary indications from FERC, we see no conflict. 57

Therefore, we conclude that the DOFs construction of the impact of the Marketable Condition Rule on the royalty-bearing nature of NGPA § 110 reimbursement payments is entirely reasonable and permissible.

B. The Effect of Diamond Shamrock

Mesa relies heavily on our 1988 decision in Diamond Shamrock, 58 arguing that it uncategorically prohibits assessment of royalties on costs for treatment of gas after the gas is physically severed from the earth. The DOI counters, and the district court found, that Diamond Shamrock involved a different question than the case before us and does not provide support for Mesa’s position. We agree.

In Diamond Shamrock we were asked to determine whether the DOI could obtain royalties on take-or-pay monies received by the producing lessee for gas not taken. We held that producers leasing offshore lands from the DOI were not required to pay royalties on monies received from pipeline purchasers as take-or-pay payments under the purchase contract. 59

Our discussion focused on the meaning of “production” in the context of OCSLA § 8, which requires that royalty be based on the “amount or value of the production saved, removed, or sold.” 60 We concluded that take-or-pay provisions provide payment for the pipeline-purchaser’s failure to purchase gas, and therefore could not be royalty-bearing as a sale of “production” under OCSLA. 61 Diamond Shamrock had nothing whatsoever to do with treatment costs, the Marketable Condition Rule, or § 110 reimbursement payments. We did not interpret these concepts, nor was there any reason that we should have. Nor did we resolve or address the question of how to assess the “fair market value” of gas produced. In essence, we held that royalty valuation could not begin until gas constitutes “production saved, removed or sold” —physically severed “from the formation” and “delivered to the pipeline.” 62

But we know that this does not end the inquiry. Where the producer treats the gas, as is required under the Marketable Condition Rule, royalties are not assessed on the value of the gas in raw form, or exclusive of costs, but on the “gross proceeds” received from the purchaser, often the ceiling price mandated under the NGPA, without deduction for the costs of marketing. 63 To contend, as Mesa does, that our definition of “production” in Diamond Shamrock mandates a distinction between proceeds accruing from sale of the gas itself and reimbursement receipts for the producer’s treatment of the gas would lead to absurd results in contravention of the Marketable Condition Rule and the plain meaning of the standard phrase “gross proceeds.” 64 Diamond Shamrock does not allow this quantum leap.

Conclusion

For the foregoing reasons, we conclude that the district court properly determined that the DOI correctly interpreted the regulations as they apply to royalty owing on § 110 reimbursements.

AFFIRMED.

1 . 15 U.S.C. § 3320(a), infra note 10.

2 . 43 U.S.C. §§ 1331-1356 (1988).

3 . 43 U.S.C. § 1334(a).

4 . Secretarial Order No. 3071 (Jan. 19, 1982) [47 Fed.Reg. 4757 (Feb. 2, 1982) ].

5 . 43 U.S.C. § 1337(a)(l)(A, B).

6 . 30 C.F.R. § 250.64 (1954-79) (emphasis added) [19 Fed.Reg. 2659 (May 8, 1954) ], redesig-nated as amended at 30 C.F.R. § 206.150 (1987) [48 Fed.Reg. 35641 (Aug. 5, 1983) ]. The 1983 codification was in effect during the time period relevant to this appeal. This rule has been modified a third time but retains its essence. See 30 C.F.R. §§ 206.152(h) (unprocessed gas), 206.153(h) (processed gas) (1990) [53 Fed.Reg. 1272 (Jan. 15, 1988) ].

7 . Treatment services performed and at issue here include measuring, gathering, compressing, sweetening, and dehydrating (desulphurization) the gas, where necessary to render it marketable.

8 . 30 C.F.R. § 250.42 (1987) [44 Fed.Reg. 61892 (Oct. 26, 1979) ] amending 30 C.F.R. § 250.41(b) (1968) [19 Fed.Reg. 2656 (May 8, 1954) ]. This provision was amended in 1988 and now provides:

The lessee is required to place gas in marketable condition 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(i) (1990) [53 Fed.Reg. 1272 (Jan. 15, 1988) ]; see also 30 C.F.R. § 206.153(i) (1990) (processed gas); infra note 52.

9 . 15 U.S.C. §§ 3301-3432.

10 . 15 U.S.C. § 3320(a).

11 . See FERC Order Nos. 94, 94-A, and 94-B, codified at 18 C.F.R. §§ 271.1100-271.1106 (1990) [45 Fed.Reg. 53099 (Aug. 11, 1980); 48 Fed.Reg. 5152 (Feb. 3, 1983); 48 Fed.Reg. 5190 (Feb. 3, 1983) ] [hereafter referred to as "the Order 94 regulations’’]. See also Texas Eastern Transmission Corp. v. Federal Energy Regulatory Comm’n, 769 F.2d 1053, 1060 n. 8 (5th Cir.1985), cert. denied, 476 U.S. 1114, 106 S.Ct. 1967, 90 L.Ed.2d 652 (1986).

12 . 18 C.F.R. § 271.1104(a) (1990).

13 . 18 C.F.R. § 271.1104(c)(7)(i) (1990).

14 . See 18 C.F.R. § 271.1104(d)(1) (1990).

15 . See 18 C.F.R. § 271.1104(d)(2) (1990).

16 . 769 F.2d 1053.

17 . Both prior to and after the Texas Eastern decision, the MMS’s policy has been to include § 110 payments in the lessees’ "gross proceeds” for royalty valuation purposes. Mesa itself operated for some time under the DOI’s interpretation of the royalty valuation on § 110 payments, see infra note 20, and stated at oral argument that the DOI Inspector-General first demanded unpaid royalties on § 110 reimbursements from Mesa in August 1983. Also, the record from the DOI hearing in this case includes documentary evidence that the MMS’s policy has been consistent. See, e.g., Admin. Rec. v. 1.5 (July 22, 1985, Memorandum from Chief, Royalty Valuation and Standards Division to Regional Manager, Houston Office the Royalty Compliance Division of MMS, regarding royalty valuation of the El Paso Natural Gas Co., stating that ”[m]onies received by the seller for production-related costs are a part of the gross proceeds accruing to the lessee and therefore are subject to royalty”). See also Policy Regarding Procedures for Calculating Royalty Values, Santa Fe Energy Co., enclosed with letter of May 7, 1986:

The MMS’s policy is that monies received ... by the lessee (seller) to offset the incurrence of “production-related costs” (FERC Order 94 monies) are considered a part of the gross proceeds upon which royalties are due.

Admin. Rec. v. 1.3.

18 . Admin. Rec. v. 1.1.

19 . The Mesa/DOI lease provides in part:

Royalty on production [Lessee is obligated] to pay the lessor a royalty of 162/3 percent in an amount or value of production saved, removed or sold from the leased area. Gas of all kinds (except helium and gas used for purposes of production from and operation upon the leased area or unavoidably lost) is subject to royalty.

It is also undisputed that Mesa agreed in the lease that the Secretary of the Interior may establish minimum values for purposes of computing royalty on products obtained from the lease, "due consideration being given to the price received by the lessee,” and that the terms of OCSLA and its implementing regulations are incorporated into the lease.

20 . By letter dated December 30, 1986, Mesa also sought a $954,574.12 refund of royalty on § 110 payments it claimed (under its interpretation of the regulations) it had overpaid the DOI. The February 1987 audit letter came after this refund request and began the proceedings which ultimately gave rise to this appeal. The question of the amount of royalty due is not before this Court, only whether the DOI may legally demand the royalty.

21 . Id.

22 . 30 C.F.R. § 250.42; see supra note 8.

23 . See F.R.Civ.P. 73.

24 . 853 F.2d 1159 (5th Cir.1988).

25 . Id. at 1167.

26 . 5 U.S.C. § 706(2)(A).

27 . Diamond Shamrock, 853 F.2d at 1165 (citing Chevron, U.S.A., Inc. v. Natural Resources Defense Council, 467 U.S. 837, 843, 104 S.Ct. 2778, 2781-82, 81 L.Ed.2d 694, 703 (1984). See also, Amoco Production Co. v. Lujan, 877 F.2d 1243, 1248 (5th Cir.), cert. denied, — U.S. -, 110 S.Ct. 561, 107 L.Ed.2d 556 (1989) (agency's interpretation of law must be honored so long as it is a reasonable one).

28 . See Diamond Shamrock, 853 F.2d at 1165.

29 . See supra notes 27-28.

30 . In any event, such a challenge would be time-barred. See 28 U.S.C. § 2401(A); see also Sierra Club v. Penfold, 857 F.2d 1307, 1315 (9th Cir.1988); Impro Products, Inc. v. Block, 722 F.2d 845, 850 (D.C.Cir.1983), cert. denied, 469 U.S. 931, 105 S.Ct. 327, 83 L.Ed.2d 264 (1984).

31 . See E. Kuntz, Oil and Gas § 60.2, at 123-24 (1978).

32 . Pub.L. No. 75-688, 52 Stat. 821 (codified as amended at 15 U.S.C. §§ 717-717w (1988)).

33 . 15 U.S.C. § 717.

34 . Pub.L. 75-688, § 4, 52 Stat. 822.

35 . See Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (1954).

36 . See Note, Legislative History of the Natural Gas Policy Act: Title I, 59 Tex.L.Rev. 101, 107-12 (1989) [hereafter "Legislative History of NGPA”].

37 . See id. at 108.

38 . Statement of General Policy No. 61-1 (Rate Standards for Independent Natural Gas Producers), 24 F.P.C. 818, 35 P.U.R.3d 195 (1960).

39 . In proceedings on the area rate regulations, the FPC stated:

[W]e shall provide an opportunity for producers to petition for special relief from the area rate.... We cannot here visualize all of the circumstances which may serve as the basis for such relief, and will provide adequate flexibility to consider claims to such entitlement, but it is obvious that more must be shown than that the individual producer’s costs exceed composite costs.

Area Rate Proceeding For Permian Basin, 34 F.P.C. 159, 180, 59 P.U.R.3d 417, 444-45 (1965) (Op. No. 468), aff’d in part sub nom. Shelly Oil Co. v. FPC, 375 F.2d 6 (10th Cir.1967), aff’d in part sub nom. Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968) (quoted in Legislative History of NGPA, supra note 36, at n. 52).

40 . See Legislative History of NGPA, supra note 36, at 110-11; [1972] F.P.C.Ann.Rep. 49.

41 . 15 U.S.C. § 3312 (establishing ceiling price for "new natural gas and certain natural gas produced from the [OCS]," and granting favorable pricing treatment to gas produced as a result of new exploration).

42 . 15 U.S.C. § 3313 (giving incentives to new developmental drilling).

43 . 15 U.S.C. § 3317 (providing special pricing for "high-cost natural gas”).

44 . 15 U.S.C. § 3318 (setting incentive price for "stripper wells”).

45 . 15 U.S.C. § 3320; see supra note 10, and accompanying text.

46 . See supra notes 10-15, 40.

47 . See e.g., The Texas Company, 64 I.D. 76 (1957) (holding that special “handling charges” recouped from pipeline purchasers under extraordinary circumstances were royalty-bearing).

48 . See California Co. v. Udall, 296 F.2d 384 (D.C.Cir.1961), aff’g 187 F.Supp. 445 (D.D.C.1960), and The California Co., 66 I.D. 54 (1959); Placid Oil Co., 70 I.D. 436 (1963).

We consider this a clear interpretation of the Marketable Condition Rule. Therefore, we decline Mesa’s and amici’s invitation to import commonly understood meanings of lease terms from cases decided in the state courts of this Circuit. See 43 U.S.C. § 1333; Nations v. Morris, 483 F.2d 577, 589 (5th Cir.), cert. denied, 414 U.S. 1071, 94 S.Ct. 584, 38 L.Ed.2d 477 (1973) (when construing OCS lease, state law only applicable when necessary to fill significant void or gap); Continental Oil Co. v. London S.S. Owners' Mut. Insur. Ass'n, 417 F.2d 1030, 1035-36 (5th Cir.1969), ce rt. denied, 397 U.S. 911, 90 S.Ct. 911, 25 L.Ed.2d 92 (1970) (same).

The most recent amendment to the Marketable Condition Rule expressly incorporates the DOI's interpretation that no marketing costs may be deducted from the gross proceeds on which royalty is calculated. See 30 C.F.R. §§ 206.152(i), 206.153(i) (1990), supra note 8.

49 . 115 I.B.L.A. 393 (1990).

50 . Id. at 396. Certain cases which Mesa and amici contend provide authority for their position instead illustrate this exception. See e.g., Marathon Oil Co. v. United States, 604 F.Supp. 1375 (D.Alaska 1985), aff'd, 807 F.2d 759 (10th Cir.1986), cert. denied, 480 U.S. 940, 107 S.Ct. 1593, 94 L.Ed.2d 782 (1987) (allowance for transportation to far distant market in Japan deductible).

We also point out that cases involving non-federal parties, also urged as authority by Mesa and amici, only confirm that royalty obligations are to be determined by the lease terms and incorporated statutory provisions. See supra note 48; see also Bowers v. Phillips Petroleum Co., 692 F.2d 1015 (5th Cir.1982) (determining “market value” and royalty owing under terms of Texas lease); Ashland Oil & Refining Co. v. Staats, Inc., 271 F.Supp. 571, 577 (D.Kans.1967) (allowing deduction for post-production services under express provision in lease between non-federal parties).

51 . See California Co., 296 F.2d at 388.

52 . At oral argument, counsel for Mesa for the first time suggested that the DOI’s interpretation improperly results in- a royalty "in value” which would be different from a royalty "in kind,” in contravention of "hornbook law." This argument was neither presented to nor passed on by the district court, nor was it raised in any of the briefs to this Court. We therefore need not reach it. See Picco v. Global Marine Drilling Co., 900 F.2d 846, 849 n. 4, 1990 A.M.C. 1976, 1979 n. 4 (5th Cir.1990) (argument not presented to district or circuit court before oral argument not preserved for appeal); Clark v. Aetna Cas. & Sur. Co., 778 F.2d 242, 249 (5th Cir.1985).

In any case, we reject Mesa's suggestion. The case which Mesa cited, ARCO Oil Co., 115 I.B. L.A. 393, does not support its proposition that royalty taken in kind must always equal royalty taken in value. See supra note 50. Indeed, it will always be the case that royalty owners may realize some benefit from taking their royalty in kind rather than in value, or vice versa, under the proper reading of the Marketable Condition Rule, which Mesa has failed to employ. See supra notes 48-51, and accompanying text.

53

54 . See 853 F.2d at 1167; infra section III.B.

55 . See 48 Fed.Reg. 5152, 5153 (Feb. 3, 1983).

56 . See 18 C.F.R. § 271.1104(c)(7)(i) (1990) [48 Fed.Reg. at 5153], supra note 13.

57 . This is unlike Diamond Shamrock, 853 F.2d at 1167-68, discussed infra Section III.B, where the conflict was clear. Generally speaking, as with the NGPA, Order 94 is directed to the producer-purchaser relationship and does not address allocation of payments under the lease between the DOI-lessor and the producer-lessee, which is governed by regulations originally enacted some 27 years earlier. See supra notes 6-8.

58 . 853 F.2d 1159.

59 . Id. at 1168.

60 . Id. at 1165-67. See 43 U.S.C. § 1337(a)(l)(A, B), supra note 5.

61 . See id. at 1167.

62 . Id. at 1168, 1165.

63 . 30 C.F.R. § 250.42 (1987), supra note 8.

64 . 30 C.F.R. § 206.150 (1987), supra note 6.