Diamond Shamrock Exploration Co. v. Hodel

JOHN R. BROWN, Circuit Judge: The issue raised is whether payments by a pipeline-purchaser to a lessee-producer of a federal oil and gas lease pursuant to a take-or-pay clause in its gas sales contract with the pipeline-purchaser are subject to payment of a royalty when the take-or-pay payment is received, not as value for gas actually taken, but as part of the take-or-pay obligation under the contract. This is another of the now prevalent take-or-pay cases with which we and others are now frequently faced. It comes to us as consolidated appeals from conflicting judgments rendered in the Western and Eastern Districts of Louisiana (Veron and Sear, J.J., respectively). We agree with the lessee-producers that royalty payments are not due on take-or-pay payments and are only due on gas actually produced and taken. We affirm the judgment of the Western District and reverse the judgment of the Eastern District.1 I. Proceedings Below A. The Mesa Case In 1973, Mesa leased submerged, offshore lands from the United States pursuant to OCSLA.2 Under the standard government oil and gas lease, Mesa was required to pay a royalty of 16%% in amount or value of “production saved, removed or sold from the leased area.” Mesa thereafter sold all of the gas produced from these federal leases to Tennessee Gas Pipeline Company under an exclusive long-term contract by which all of Mesa’s production was committed to the contract. The contract with the pipeline included a take-or-pay provision requiring Tennessee to take a specified amount of gas during each contract year or pay for that quantity even if not taken in full. A seven-year make-up period was provided during which Tennessee was able to credit the price of gas later taken in excess of the required minimum (referred to as “make-up gas”) against earlier take-or-pay payment obligations. Mesa periodically paid royalties to the United States through the Minerals Management Service (MMS) of the Department of the Interior (DOI) on all gas currently delivered to the pipeline. Mesa did not pay royalties on take-or-pay payments received from Tennessee. Royalties were calculated and paid only if, and only to the extent, make-up gas was taken. — 1162 — After an audit, MMS ordered Mesa to pay royalties on the take-or-pay payments Mesa had received from Tennessee. Prior to this audit, Mesa had not paid royalties on take-or-pay payments. Mesa calculated and paid its royalty obligation based on payments for gas actually taken, as gas was actually taken, based on the price of gas at the time it was taken. Based on this audit, MMS also notified Mesa that interest charges would be assessed for royalties paid on make-up gas from the time the take-or-pay payment for that quantity of gas was received. This order assessing payments and interest penalties was appealed to the Director of MMS who ultimately affirmed MMS’ authority to collect royalties on take-or-pay receipts.3 The Department of the Interior, through the Assistant Secretary for Land and Minerals Management, adopted the Director’s decision as the final decision of the DOI. Mesa appealed this order in the Western District of Louisiana. Judge Yeron of the Western District found that the purpose of the take-or-pay provision was to ensure Mesa a steady flow of revenue to meet operation and maintenance costs. The lease agreement between the United States and Mesa entitled the government to receive 16% percent of production saved, removed or sold from the leased areas. To the extent take-or-pay payments were made in lieu of taking gas, there was no production, and Mesa had no obligation to make royalty payments thereon. MMS was therefore without authority to collect royalties on such take-or-pay receipts. Judge Veron set aside the order which required Mesa to pay royalties on take-or-pay receipts, 647 F.Supp. 1350. The government appeals. B. The Diamond Shamrock Cases These cases, consolidated in the Eastern District, present virtually the same situation. Diamond Shamrock, Cities Service, Exxon, Mobil and Texaco (and various subsidiaries) are lessees under numerous leases 4 on the offshore Louisiana Outer Continental Shelf.5 These lessees uniformly failed to pay royalties on take-or-pay payments unless make-up gas had been taken, in which case royalties were calculated and paid based on the price of the gas at the time the make-up gas was taken. As in Mesa, the MMS ordered the lessee-producers to pay royalties on take-or-pay revenues received. It additionally assessed interest charges for late payment, asserting that the royalty payment was due at the time the take-or-pay payment was made, not the time at which the make-up gas was taken. The lessees appealed to the MMS Director, who affirmed the order.6 Cities Service and Exxon had paid royalties on some, but not all, of their take-or-pay revenues. Exxon and Cities Service requested refunds for royalties paid on such take-or-pay revenues. The MMS denied the request. Cities Service and Exxon appealed the denial of their requests to the MMS Director. The Director affirmed the denial.7 — 1163 — On cross motions for summary judgment, Judge Sear of the Eastern District treated take-or-pay payments as the equivalent of advance payments for gas, similar to an interest-free loan from the pipeline. As this raised the price of gas purchased by the pipeline, take-or-pay payments were to be taken into account in calculating the “value” of the production removed, and were subject to royalty. Judge Sear’s reasoning was based in part on the definition of “production” contained in OCSLA: The term “production” means those activities which take place after the successful completion of any means for the removal of minerals, including such removal, field operations, transfer of minerals to shore, operation monitoring, maintenance and work-over drilling.8 Judge Sear held that, as take-or-pay payments are intended to compensate the producer for maintenance and other activities necessary to keep wells functioning, they fall within this definition of payments for production. Consequently, Judge Sear sustained the DOI’s decisions and expressly rejected the holding of the Western District in Mesa. The lessee-producers appealed.9 II. Bird’s Eye View of Oil and Gas Law A. The Lease Itself The standard oil and gas lease issued by the government10 and signed by these lessee-producers is fairly straightforward. The lessee-producers are required to pay11 the lessor-government a royalty of “16% percent in amount or value of production saved, removed, or sold from the leased area.” 12 The lease further provides: “It is expressly agreed that the Secretary [of the DOI] may establish reasonable minimum values for purposes of computing royalty on products obtained from this lease, due consideration being given to the highest price paid for a part or for a majority of production of like quality in the same field, or area, to the price received by the lessee, to posted prices, and to other relevant matters. Each such determination shall be made only after due notice to the lessee and a reasonable opportunity has been afforded the lessee to be heard.” The royalty payment is “due and payable monthly on the last day of the calendar month next — 1164 — following the calendar month in which production is obtained.” 13 B. Producer-Pipeline Contract 1. Take-or-Pay The typical producer-pipeline contract14 provides that the pipeline will generally pay for natural gas at the maximum lawful price permitted by the Natural Gas Policy Act for the month in which the gas is produced. Gas purchases are invoiced monthly, partially in order to reflect fluctuations in price. Natural gas sales contracts usually contain a standard “take-or-pay” clause. This clause requires the pipeline-purchaser either to take (and pay for at the maximum lawful price) a specified quantity of natural gas during each contract year or to make a single annual payment to the producer to the extent that the volumes of gas taken during any contract year fall short of the minimum annual contract quantity. During a contract year, the producer receives monthly payments only for the gas actually taken. At the end of the contract year, volumes of natural gas production actually taken are compared with the minimum contract volume. In the event the pipeline has actually taken less than the contract volume, the pipeline must then make an annual lump-sum payment, the take-or-pay payment, representing the difference between the minimum contract volume for that year and the actual volume taken. Because natural gas is almost always transported by pipeline and cannot be “stored” at the lease site, if a pipeline cannot accept delivery of gas, the producer must shut in his wells or restrict production. There can be no gas produced at the time a take-or-pay payment is made because the producer has to leave in the ground reserves sufficient to meet make-up demands over the make-up period, generally five to seven years.15 The committed volume under the gas sales contract must remain in the reservoir for the remainder of the make-up period. 2. Make-Up Gas Over the next seven years, the pipeline has the right to credit excess gas taken against a previous take-or-pay payment. Whenever the pipeline purchases gas in excess of the contract volume for a subsequent year, that excess gas purchase is credited against the earlier deficiency. This excess gas is referred to as make-up gas. At the end of a year in which makeup gas is taken, the pipeline will receive a single lump-sum refund, or credit, of prior take-or-pay payments made for the earlier deficiency to the extent to which the deficiency has now been made up. The refund is calculated on the basis of the price of gas during the month in which the make-up gas was actually taken. Although the price paid for these makeup gas deliveries is the price in effect at the time the make-up gas is produced and taken, the payment is made by applying the purchaser’s prior take-or-pay payments as a credit towards the purchase price of the make-up gas. While some contracts allow the producer to retain take-or-pay payments that have not been recouped by the expiration of the make-up period, others require the producer to refund any unre-eouped payments to the purchaser. C. The Two Contracts Converge The standard government lease expressly authorizes the Secretary to establish “reasonable minimum values for purposes of computing royalty” on natural gas “obtained from” these leases. This dispute initially erupted over the Secretary’s decision to include take-or-pay revenues as part of the “reasonable minimum value” of natural gas sold. The Secretary’s interpretation stems in part from 30 C.F.R. § 206.150 which provides that “[u]nder no circumstances shall the value of production be — 1165 — less than the gross proceeds accruing to the lessee from the disposition of the produced substances_” Under the Secretary’s reasoning, the take-or-pay payment is part of the total consideration for the exclusive dedication of gas to the gas sales contract. Consequently, the Secretary has decreed take-or-pay revenues to be part of the “gross proceeds” accruing to the lessee, and subject to royalty. III. Standard of Review Before we ever reach the merits of this dispute, we must first determine the standard of review. We have before us consolidated appeals from district court judgments on review of a decision made by an administrative agency.16 Practically, our review of a decision of an administrative agency is limited to whether the decision was arbitrary or capricious. Agency findings should not be set aside unless they are “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” 17 Under this standard, the question for this court is whether the Secretary’s definition of “value” to include take-or-pay payments, regardless of whether gas is in fact ever produced or delivered, can be said to be irrational, arbitrary, an abuse of discretion, or otherwise not in accordance with law.18 The Supreme Court has provided additional guidance for courts reviewing an agency’s interpretation of a statute. Where a statute is silent with respect to the precise question at issue, the question for the reviewing court is whether the agency’s interpretation is based on a permissible construction of the statute.19 The statute in question, 43 U.S.C. § 1337(b),20 does not even remotely address the precise question of whether royalties may be collected on take-or-pay payments.- This court must therefore decide whether the DOI’s construction authorizing such collection is a permissible one.21 IV. The Merits The Secretary’s interpretation of “value” does not comport with the plain meanings of the words in the lease, and in the relevant statutes and regulations. It is obvious from a complete reading of all the relevant statutes, regulations and lease provisions, that royalties are not due on “value” or even “market value” in the abstract, but only on the value of production saved, removed or sold from the leased property. Likewise, the agency’s regulations do not refer to “gross proceeds” in the abstract, but only to gross proceeds that accrue to the lessee from the disposition or sale of produced substances, that is, gas actually removed and delivered to the pipeline. Consequently, royalties are not owed unless and until actual production, the severance of minerals from the formation, occurs. A. “Production — Production, What is Production? ”22 In order to understand this problem, it is necessary to clarify a term which has confounded the courts, as well as the Secretary, in the past. The word “production" is a horse of many colors. The Secretary and Judge Sear have juxtaposed two regulations, dealing with two totally distinct areas of oil and gas regulation in order to define the word “value” in this situation. — 1166 — The term “production” is used in the oil and gas industry in several different but related senses. The term can be used to refer to an abstract noun: (i) the act or process of producing. It can also refer to either of two concrete nouns: (ii) the products of an oil and gas well, or (iii) the well itself.23 The definition used by Judge Sear, that contained in 43 U.S.C. § 1331(m),24 relates to only one possible interpretation, the act or process of producing. Even accepting the proposition that “production” in these leases is used in the abstract noun sense, as in (i) above, this Court cannot accept the conclusion that § 1331(m) was intended by Congress to define production to exclude all other accepted meanings in the industry,25 including (ii) above, the actual products of an oil and gas well. With all due deference to the Secretary, juxtaposing the definition of § 1331(m) onto these oil and gas leases makes little sense, either economically, logically or geologically. B. What is the Value of Production? The royalty provision in the instant lease provides that royalty will be paid on “the amount or value of the production.”26 In regulations, the Department of the Interior has further defined “value of production” as “fair market value.”27 At a minimum, fair market value is at least “the gross proceeds accruing to the lessee from the disposition of the produced substances.”28 “Fair market value” is to be determined by considering several factors, which include posted prices, prices paid under comparable contracts, as well as prices paid for nonju-risdictional sales, the price actually received by the lessee, and “other relevant matters.” 29 To accept the DOI’s interpretation would lead to absurd results. For example, if royalty is payable currently when the take- or-pay payment is made, what happens when the pipeline later takes make-up gas? If the fair market value of gas rises, the pipeline is usually responsible for paying for the make-up gas at the increased market value. The government of course gets its proportionate share of the increased market value as royalty for the make-up gas now taken. The lessee-producer then has to pay the additional royalty due on the increased fair market value, necessitating two royalty payments on one purchase of gas. If the price of gas drops, depending on the contract, the pipeline-purchaser could be due a refund.30 If the pipeline gets a refund, then certainly it would be equitable for the lessee-producer to get a refund on overpaid royalties. A problem arises here with the length of the make-up period, usually 7 years, being longer than the statute of limitations against the government.31 In this situation, it is quite possible that producers would never be able to recover overpaid royalties on take-or-pay payments. If, as the DOI suggests, the fair market value of gas includes the amount of take- or-pay payments, then what result if no gas is taken? If no gas is taken under an — 1167 — exclusive sales contract, there is no market for that gas, therefore no market value of that gas. But there is a take-or-pay payment. Is that the fair market value of non-sold gas? With no production there is nothing to value either by market or otherwise. C. Characterizing the Take-or-Pay Obligation While the take-or-pay obligation is intended to compensate the producer for the exclusive commitment of reserves to a gas sales contract, this does not automatically mean that the take-or-pay obligation is part of the value of the gas.32 A take-or-pay payment which comes before gas is actually produced and taken simply cannot be a payment for a sale of gas. The purpose of take-or-pay clauses is to apportion the risks of natural gas production and sales between the buyer and seller. The seller bears the risk of production. To compensate seller for that risk, buyer agrees to take, or pay for if not taken, a minimum quantity of gas. The buyer bears the risk of market demand. The take-or-pay clause insures that if the demand for gas goes down, seller will still receive the price for the contract quantity delivered each year.33 Take-or-pay payments are not, therefore, payments for the sale of gas. Far from being payments for the purchase of gas, take-or-pay payments are payment for the pipeline-purchaser’s failure to purchase (take) gas.34 The DOI asserts, and Judge Sear accepted this assertion, that a take-or-pay payment is a benefit attributable, at least in part, to the government’s interest. We cannot agree. Take-or-pay payments are intended to compensate primarily the producer, not the owner of the minerals, for the risks associated with development production. In fact, this is the precise reason for entering into a lease agreement. The government leases oil producing lands in order to, among other things, reap the benefits, through royalty payments, without having to shoulder the associated risks of exploration, production and development. As we have long held, the take-or-pay obligation ensures to the producer a continuous source of revenue to cover investment, operations, and maintenance.35 Most of these costs have either been or will continue to be incurred, regardless of whether the purchaser takes any gas. The lessee is the exclusive bearer of these risks. The position taken by the Secretary also runs into conflict with certain regulations promulgated by the Federal Power Commission and its successor, the Federal Energy Regulatory Commission. FERC regulations and decisions attribute take-or-pay payments to make-up gas only when the gas is actually taken. For rate-making purposes, FERC treats take-or-pay payments as ^re-payments for gas not taken. Consequently, a pipeline does not recover take-or-pay payments from its customers until the pipeline takes, and thereafter sells, the make-up gas. Until the time make-up gas is taken, the take-or-pay payment is accounted for as a pre-paid asset and may not be recovered by the pipeline from its customers as a purchased gas cost.36 The most recent Commission Order, in ANR Pipeline Co. v. Wagner & Brown, — 1168 — et al.,37 reiterates this position: In the context of the gas purchase contract and industry practice, the take-or-pay payment is not intended to be a payment for gas and is not a part of the price of gas until it is applied at the time of sale. The value to the producer of take-or-pay payments forfeited by the purchaser is therefore not treated as part of the price of gas purchased currently. If the gas is made up, there has of course been a first sale and the applicable ceiling price is that in the month of delivery. . We find no basis whatever to conclude that earnings which producers may realize on take-or-pay payments, whether measured by interest actually earned or by value, are part of the price paid for gas.38 D. Putting the Puzzle Together In the interests of consistency, logic and economics, this court adopts as the legal definition of the word “production,” as used in the context of calculating royalty payments, the actual physical severance of minerals from the formation.39 For purposes of royalty calculation and payment, production does not occur until the minerals are physically severed from the earth. V. Extraneous Matters A. The Refunds Exxon and Cities Service have requested refunds for royalties paid on take- or-pay revenues. While we recognize that we have just held such royalty payments to be improper, this refund request is an action against the United States seeking monetary relief in excess of $10,000.00. Consequently, as we earlier held in Amoco Production v. Model,40 the refund claim is within the exclusive jurisdiction of the Claims Court under the Tucker Act.41 That portion of this case concerned solely with a refund of improperly paid royalties is therefore remanded to the District Court for further proceedings consistent with this opinion.42 B. Does Mesa Owe Interest? Finally, Mesa asserts that any sums due the DOI as additional royalty payments should not be subject to interest because during the years Mesa was deficient on some leases, it had overpaid on others. As we affirm the granting of summary judgment in Mesa’s favor, Mesa does not owe the DOI any additional royalties and this point is moot. Mesa has applied for a refund under the authority of 30 U.S.C. § 1711(c)(1). As with the Cities Service and Exxon refund claims, any dispute over this refund will be within the exclusive jurisdiction of the Claims Court. Consequently, we remand to the District Court for further action consistent with this opinion. Conclusion Royalty payments are due only on the value of minerals actually produced, i.e., physically severed from the ground. No royalty is due on take-or-pay payments unless and until gas is actually produced and taken. — 1169 — AFFIRMED IN PART, REVERSED IN PART AND REMANDED. Footnotes [1] This court asked for and received amicus briefs from the Federal Energy Regulatory Commission which were, under its practices in effect, an authoritative statement by the Commission, not just the General Counsel. We did this in an effort to ensure our decision would not interfere with the FERC’s authority to set natural gas policy under the NGA and NGPA. [2] Outer Continental Shelf Lands Act, 43 U.S.C. §§ 1331-1356. [3] The Director also affirmed the authority to assess late payment or interest charges on these take-or-pay royalties. [4] Diamond Shamrock is a lessee under four leases on the offshore Louisiana OCS. Cities Services is a lessee under nine leases on the Louisiana OCS. Exxon is a lessee under one lease on the Louisiana OCS. Mobil and its subsidiaries hold fifteen leases on the offshore Texas and Louisiana OCS, as well as 53 onshore leases not relevant here. Texaco holds two offshore Louisiana OCS leases. [5] In addition, Mobil and Texaco hold onshore leases issued by the DOI under the Mineral Lands Leasing Act. 30 U.S.C. §§ 181-287. Judge Sear held that the causes of action relating to the onshore leases accrued when the DOI published notices to onshore lessees in the Federal Register in 1977. Given the six year statute of limitations in 28 U.S.C. § 2401(a), the claims of the onshore lessees were time-barred. Mobil and Texaco have not appealed this issue so it is not presently before this court. [6] Apparently, in the course of the audit, the MMS discovered other take-or-pay payments on which royalties had not been paid. The lessees were ordered to render an accounting of, and pay royalty on, these other take-or-pay revenues. [7] Both Cities Service and Exxon were additionally to render an accounting of, and pay royalties on, other take-or-pay revenues. As do the other lessee-producers, Cities Service and Exxon — 1163 — contest the affirmative order to pay royalties on take-or-pay payments. [8] 43 U.S.C. § 133 l(m). [9] As the two cases involved essentially the same issues, this Court consolidated the two appeals. [10] The government oil and gas lease is issued pursuant to OCSLA, 43 U.S.C. § 1337(b), which prescribes the terms of the lease. 43 U.S.C. § 1337(b) provides: (b) An oil and gas lease issued pursuant to this section shall— (1) be for a tract consisting of a compact area not exceeding five thousand seven hundred and sixty acres, as the Secretary may determine, unless the Secretary finds that a larger area is necessary to comprise a reasonable economic production unit; (2) be for an initial period of— (A) five years; or (B) not to exceed ten years where the Secretary finds that such longer period is necessary to encourage exploration and development in areas because of unusually deep water or other unusually adverse conditions, and as long after such initial period as oil or gas is produced from the area in paying quantities, or drilling or well reworking operations as approved by the Secretary are conducted thereon; (3) require the payment of amount or value as determined by one of the bidding systems set forth in subsection (a) of this section; (4) entitle the lessee to explore, develop, and produce the oil and gas contained within the lease area, conditioned upon due diligence requirements and the approval of the development and production plan required by this subchapter; (5) provide for suspension or cancellation of the lease during the initial lease term or thereafter pursuant to section 1334 of this title; (6) contain such rental and other provisions as the Secretary may prescribe at the time of offering the area for lease; and (7) provide a requirement that the lessee offer 20 per centum of the crude oil, condensate, and natural gas liquids produced on such lease, at the market value and point of delivery applicable to Federal royalty oil, to small or independent refiners as defined in the Emergency Petroleum Allocation Act of 1973 [15 U.S.C.A. § 751 et seq.]. [11] 43 U.S.C. § 1337(b) requires the payment of a fixed percentage royalty. [12] This language essentially tracks that of 30 C.F.R. §§ 206.150 and 206.151. [13] This language is based on 30 C.F.R. § 218.50. [14] For simplicity’s sake, this general discussion is based on Mesa's contract with Tennessee. The other contracts are essentially the same. Any differences will be pointed out as necessary. [15] FERC requires the make-up period be at least five years. 18 C.F.R. § 154.103 (1987). [16] The refund claims of Exxon and Cities Service pose additional problems which will be treated separately, infra. [17] Administrative Procedure Act, 5 U.S.C. 706. [18] United States v. Morton, 467 U.S. 822, 834, 104 S.Ct. 2769, 2776, 81 L.Ed.2d 680, 691 (1984). [19] Chevron, U.S.A., Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837, 843, 104 S.Ct. 2778, 2781-82, 81 L.Ed.2d 694, 703 (1984). [20] See n. 10, supra. [21] Both Judges Veron and Sear correctly identified the standard of review, but arrived at different results, partly because the judges gave different degrees of deference to the interpretation of the Secretary. Because we hold that the DOI's interpretation does not comport with either the intent of Congress or the plain words of the leases and regulations, this court is entitled to reach a contrary conclusion. [22] Amoco Production Co. v. Sea Robin Pipeline Co., 844 F.2d 1202, 1207 (5th Cir.1988). [23] See Williams and Meyers, Oil and Gas Law (Manual of Terms) 755 (1969); see abo Sea Robin, supra, n. 22. [24] 43 U.S.C. § 133 l(m) provides: (m) The term "production” means those activities which take place after the successful completion of any means for the removal of minerals, including such removal, field operations, transfer of minerals to shore, operation monitoring, maintenance, and work-over drilling. [25] See Sea Robin, supra. [26] 43 U.S.C. § 1337(a)(1)(B). [27] 30 C.F.R. § 206.150. [28] Id. [29] Id. [30] See generally 18 C.F.R. § 154.103 (1987). [31] Section 1339 of OCSLA authorizes a refund of royalties only if the lessee files a request for the “amount of such refund” within "two years after the making of the payment.” The Solicitor for the DOI has determined that this language requires the lessee to request a specific amount of refund within the two-year period. While the ■ requirement that a specific amount be stated has eased somewhat, the precise requirements for refund requests are still unclear. Refunds and Credits Under the Outer Continental Shelf Lands Act, 88 I.D. 1090, 1099, 1100 (1981); Shell Offshore, Inc., 96 IBLA 149, 174-75 (1987). [32] An analogy may be drawn to the purchaser of a lottery ticket who pays one dollar for the chance to win a million dollars. An equal inequity would result were the government to attempt to assess a tax on the million at the time the purchaser purchases the ticket, long before the million dollars is even capable of being won. [33] Universal Resources Corp. v. Panhandle Eastern Pipeline Co., 813 F.2d 77, 80 (5th Cir.1987). [34] Pennzoil Co. v. Wyoming, No. 104-35 (5th Jud.Dist.Wyo.), March 20, 1986, aff'd, Wyoming v. Pennzoil, 752 P.2d 975 (Wyo.1988). [35] While the government shares none of these expenses, it does provide itself with a stead supply of revenue through provisions for a "minimum royalty" in the event there is little or no royalty bearing production. [36] See generally Statement of Policy and Interpretative Rule: Regulatory Treatment of Payments Made in Lieu of Take-or-Pay Obligations, FERC Stats. & Regs. [Regs. Preambles 1982-1985] ¶ 30, 637 at p. 31, 301 (1985). [37] Docket Nos. GP86-54-000. [38] Order at 7-8. [39] This definition is consistent with, and indeed identical to, definitions adopted by other courts. See Interstate Natural Gas v. FPC, 331 U.S. 682, 690, 67 S.Ct. 1482, 1487, 91 L.Ed. 1742, 1748 (1947) (production involves a physical act); Energy Oils v. Montana Power Co., 626 F.2d 731, 738 (9th Cir.1980); Saturn Oil & Gas Co. v. FPC, 250 F.2d 61, 64 (10th Cir.1957), cert. denied, 355 U.S. 956, 78 S.Ct. 542, 2 L.Ed.2d 532 (1958) (act of bringing forth gas from the earth); Wyoming v. Pennzoil Co., 752 P.2d 975, 979 (Wyo.1988) (production requires severance of mineral from ground); Exxon Corp. v. Middleton, 613 S.W.2d 240, 244 (Tex.1981) (requires extraction of gas); Monsanto Co. v. Tyrrell, 537 S.W.2d 135, 137 (Tex.Civ.App.1976) (actual physical severance); Christian v. A.A. Oil Corp., 161 Mont. 420, 428, 506 P.2d 1369, 1373 (1973) (withdrawn from land and reduced to possession); Continental Oil Co. v. Landry, 215 La. 518, 41 So.2d 73, 75 (1949) (requires extraction). [40] Amoco Production Co. v. Hodel, 815 F.2d 352 (5th Cir.1987). [41] 28 U.S.C. §§ 1346(a)(2) and 1491(a). [42] 28 U.S.C. § 1631.