Case ID: f3d_244/html/1341-01.html
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Author: {"author": "MICHEL, Circuit Judge.", "license": "Public Domain", "url": "https://static.case.law/"}
Date Created: 2024-08-24T03:29:51.129683

EXXON MOBIL CORPORATION and Subsidiaries, Plaintiff-Appellant, v. UNITED STATES, Defendant-Cross Appellant.
    Nos. 00-5048, 00-5049.
    United States Court of Appeals, Federal Circuit.
    Decided April 3, 2001.
    
      Robert L. Moore, II, Miller & Chevalier, Chartered, of Washington, DC, argued for plaintiff-appellant. With him on the brief were Thomas D. Johnston, Alan I. Horowitz, Patricia J. Sweeney, and Mark V. Holmes.
    Thomas J. Sawyer, Attorney, Tax Division, Department of Justice, of Washington, DC, argued for defendant-cross appellant. With him on the brief were Thomas J. Clark, Attorney.
    Before NEWMAN, MICHEL, and RADER, Circuit Judges.
   MICHEL, Circuit Judge.

This is a federal income tax case. Appellant Exxon Mobil Corporation (“Exxon”) appeals the December 29, 1999 judgment of the United States Court of Federal Claims denying-in-part Exxon’s claim for a reimbursement for federal income taxes paid for the 1975 tax year on proceeds from sales of natural gas. The United States cross-appeals the trial court’s decision, arguing that the court applied an incorrect legal standard in determining whether Exxon was entitled to its claimed deductions. Exxon filed a timely notice of appeal to this court on February 14, 2000. The government filed a timely cross-appeal on February 17, 2000. This court has jurisdiction pursuant to 28 U.S.C. § 1295(a)(3). We heard oral arguments in this appeal on February 5, 2001. Because we find that the trial court applied the proper legal standard in determining whether Exxon was entitled to calculate its deduction based on percentage depletion, we affirm the trial court’s judgment on the government’s cross-appeal. On Exxon’s appeal, we find no clear error in the trial court’s ruling that Exxon failed to carry its burden of demonstrating that the casinghead gas sold pursuant to the contracts at issue was entitled to the claimed deduction, and accordingly we affirm the trial court’s judgment on the casinghead gas issue. However, we conclude that the Excess Royalty Reimbursement clause of Exxon’s contract with Houston Light & Power Company (“HL & P”) is equivalent, as a matter of law, to the permissible price increase provisions recited in Treas. Reg. § 1.613A-7(c)(5). Moreover, we conclude that the Additional Gas clause of the HL & P contract did not disqualify the contract from being treated as a “fixed contract” under I.R.C. § 613A(b)(2)(A) because the challenged price increases were equivalent to an above-market surcharge on additional gas, and because HL & P, not Exxon, retained control over whether the price increases would occur. Accordingly we reverse the conclusion of the trial court that the HL & P contract was disqualified from treatment as a “fixed contract” under I.R.C. § 613A(b)(2)(A). We remand for calculation of the amount of the tax refund owed to Exxon.

I. Factual and Procedural Background

At issue is whether Exxon is entitled to calculate federal income tax deductions for sales of natural gas sold under fixed-price contracts during the 1975 tax year pursuant to a highly favorable representative market or field price (“RMFP”), and whether certain particular transactions qualify for this favorable tax treatment. The legal background concerning the federal income tax deductions at issue is described with great clarity and detail in the trial court’s summary judgment and post-trial opinions, which total more than 300 pages in length. The following summary of the most pertinent aspects of the Tax Code and governing regulations, as well as the procedural history of the present case, has been adapted in part from the trial court’s opinion.

A. The Role of “Percentage Depletion” and the “RMFP”

“Ever since enacting the earliest income tax laws, Congress has subsidized the development of our nation’s natural resources.” Commissioner v. Engle, 464 U.S. 206, 208, 104 S.Ct. 697, 78 L.Ed.2d 420 (1984). Until 1975, Congress generally permitted holders of economic interests in oil and gas wells “to deduct from then-taxable incomes the larger of two depletion allowances: cost or percentage.” Id. Cost depletion, which is not at issue in this case, permits the taxpayer to amortize the cost of his wells over the wells’ total productive life. Id. Percentage depletion is based upon the income generated by the property throughout its entire productive life, rather than the cost of such property, and accordingly may yield deductions significantly exceeding the amount the taxpayer paid for the property. Id. (“Taxpayers have historically preferred the allowance for percentage, as opposed to cost, depletion on wells that are good producers because the tax benefits are significantly greater.”).

Prior to 1975, section 613 of the Tax Code set forth a formula governing the extent to which oil and gas producers were entitled to calculate percentage depletion. This formula based the amount of the deduction on the “gross income from the property.” I.R.C. § 613(a) (1974). The pertinent sections of the Code provided:

(a) General rule.
In the case of the mines, wells, and other natural deposits listed in subsection (b), the allowance for depletion under section 611 shall be the percentage, specified in subsection (b), of the gross income from the property ....
(b) Percentage depletion rates.
The mines, wells, and other natural deposits, and the percentages, referred to in subsection (a) are as follows:
(1) 22 percent
(A) oil and gas ivells [.]

I.R.C. §§ 613(a), (b)(1)(A) (1974) (emphasis added). Thus, under pre-1975 law, an oil or gas producer’s annual allowance for percentage depletion was 22% of the producer’s gross income from sales of natural gas extracted from the property, subject to certain limitations. See id; Exxon Corp. v. United States, 88 F.3d 968, 971 (Fed.Cir.1996) (“Exxon I”). The Code did not define the term “gross income from the property,” but delegated to the Secretary of the Treasury the task of determining allowances for percentage depletion. See I.R.C. § 611(a) (1974) (providing that allowances for percentage depletion are “in all cases to be made under regulations prescribed by the Secretary or his delegate”).

Pursuant to the foregoing delegation of rulemaking authority, the Secretary promulgated a Treasury Regulation providing a method of calculating “gross income from the property.” As effective in 1974, Treasury Regulation § 1.613-3(a) provided:

Gross income from the property.
(a) Oil and gas wells. In the case of oil and gas wells, “gross income from the property”, as used in section 613(c)(1), means the amount for which the taxpayer sells the oil or gas in the immediate vicinity of the well. If the oil or gas is not sold on the premises but is manufactured or converted into a refined product prior to sale, or is transported from the premises prior to sale, the gross income from the property shall be assumed to be equivalent to the representative market or field pnce of the oil or gas before conversion or transportation.

Treas. Reg. § 1.613-3(a) (1974) (emphasis added). On appeal, neither party questions the validity of this regulation. This regulation is designed to equalize a disparity in the deductions that may be taken by non-integrated and integrated oil and gas producers. Non-integrated producers simply produce raw gas and sell that gas in the field to a pipeline or a gas processing plant. Integrated producers, like Exxon, process and transport the gas prior to sale. Exxon I, 88 F.3d at 968. Because integrated producers bear the cost of post-extraction processing and transportation, they are able to sell gas at a higher price than non-integrated producers, and hence realize more gross income per unit of natural gas sold. Accordingly, integrated producers would be able to claim a higher deduction per unit- of gas than non-integrated producers, absent a corrective mechanism. See id. at 970.

Treasury Regulation § 1.613 — 3(a) (1974) provided a method of maintaining integrated and non-integrated producers on an equal competitive footing for purposes of computing percentage depletion allowances. The regulation provided that a constructive value shall be calculated for gas that is “not sold on the premises but is manufactured or converted into a refined product [or transported] prior to sale.” Treas. Reg. § 1.613 — 3(a) (1974). This constructive value, or representative market or field price (“RMFP”), represents the value of comparable gas sold in the immediate vicinity of the well, without the added value of post-extraction processing and transportation. The RMFP of natural gas “is calculated as the weighted average price of wellhead sales of comparable gas in the taxpayer’s market area.” Exxon I, 88 F.3d at 976. As explained by the trial court, the RMFP determination has three distinct elements: (i) the relevant market area; (ii) the comparability of the gas produced in such market area to the taxpayer’s gas; and (iii) the qualification of sales of comparable gas in such market area as wellhead sales of unprocessed gas, ie., sales of raw gas made “in the immediate vicinity of the well,” within the meaning of Treas. Reg. § 1.613-3(a). Exxon Corp. v. United States, 45 Fed.Cl. 581, 592-93 (1999) (“Exxon II”).

B. Exxon’s Fixed Contracts and the Impact of the Arab Oil Embargo

The sales of natural gas at issue pertain to natural gas sold at relatively low prices pursuant to 18 long-term contracts entered into between 1955 and 1972. Exxon characterizes these contracts as “fixed price” contracts, as Exxon purportedly lacked the ability to increase the price of the gas sold pursuant to these contracts to reflect increases in the market price of the gas. In the late 1960s and early 1970s, the price of oil and gas soared, in part due to the Arab oil embargo. Regarding its gas sales under the 18 contracts at issue in this case, Exxon was purportedly unable to take advantage of the rising market prices due to 'the “fixed price” nature of the contracts. The discrepancy between its actual sales prices and the going market prices, however, created an opportunity for Exxon to claim abnormally high income tax deductions.

Integrated oil and gas producers, such as Exxon, noted that Treasury Regulation § 1.613-3(a) required them to calculate their income tax deduction based on an RMFP, rather than on the actual prices obtained from sales of the gas. Because market prices were far higher than the prices actually obtained, calculating a deduction based on an RMFP permitted integrated oil and gas producers to claim deductions far in excess of what they would otherwise be permitted to deduct based on actual income from the property. In Exxon I, we considered the propriety of allowing gas producers to calculate their deductions based on an RMFP that exceeds the price actually charged for the gas sold. See Exxon 1, 88 F.3d at 971. Although recognizing that a straight-forward application of the RMFP might give integrated producers a “competitive tax advantage over nonintegrated producers,” we noted that “the plain language of the tax scheme supports Exxon’s contention” that the RMFP is not limited to actual gross income, and concluded that “it is not within our judicial powers to legislate in [the Secretary’s] stead.” Id. at 974-75. Accordingly, we ruled that Exxon was entitled to a percentage depletion deduction based on an RMFP for its sales of natural gas in 1974. Id. at 981.

C. The 1975 Repeal of Percentage Depletion

The present appeal requires us to determine to what extent Exxon I remains applicable in the wake of 1975 amendments to the Tax Code concerning percentage depletion. By 1975, Congress grew convinced that the continuing need to provide a tax incentive for oil and gas exploration and production, i.e., percentage depletion, was outweighed by the public outcry over the nation’s increasing dependence on foreign oil and gas, the Arab oil embargo, soaring energy prices, and the perceived windfall profits being reaped by the major integrated oil and gas companies, Exxon included. See Engle, 464 U.S. at 211, 104 S.Ct. 597; Exxon I, 88 F.3d at 970. Consequently, with the enactment of the Tax Reduction Act of 1975, Pub.L. No. 94-12, 89 Stat. 26, 47-53 (March 29, 1975) (the “1975 Act”), Congress repealed the allowance for percentage depletion as it applied to the major integrated oil and gas companies, subject to certain exemptions. Effective January 1, 1975, with application to taxable years ending after December 31, 1974, newly enacted I.R.C. § 613A provided:

§ 613A. Limitations on percentage depletion in case of oil and gas wells.
(a) General rule.
Except as otherwise provided in this section, the allowance for depletion under section 611 with respect to any oil or gas well shall be computed without regard to section 613.
(b) Exemption for certain domestic gas wells
(1) In general.
The allowance for depletion under section 611 shall be computed in accordance with section 613 with respect to—
(B) natural gas sold under a fixed contract....
and 22 percent shall be deemed to be specified in subsection (b) of section 613 for purposes of subsection (a) of that section.

I.R.C. §§ 613A(a), (b) (1975). One notable exemption from the repeal of percentage depletion, which is the focus of the present dispute, is for “natural gas sold under a fixed contract.” I.R.C. § 613A(b)(l)(B) (1975). This exemption represents an apparent legislative compromise, which, Exxon argues, allowed integrated oil and gas producers selling under fixed-price contracts to continue to take percentage depletion deductions, in recognition of their inability to profit from the soaring market. According to a House Report accompanying the bill, Congress recognized that percentage depletion would be only “phased out,” and that the repeal would have an immediate impact only on 15-20% of sales of natural gas, with the remaining sales falling within exemptions to the repeal, including that for gas sold under fixed contracts. See H.R.Rép. No. 93-1502, at 54 (1974) (“With the two exemptions referred to above in effect, the phaseout initially will apply to 15 to 20 percent of natural gas produced in the United States.”).

The 1975 Act provided a narrow definition of the term “natural gas sold under a fixed contract,” stating that under such a contract, “the price of gas cannot be adjusted to reflect to any extent” the seller’s increased tax liabilities due to the repeal of percentage depletion. I.R.C. § 613A(b)(2)(A) (1975). The definition, in full, provided:

(2) Definitions
(A) Natural gas sold under a fixed contract.
The term “natural gas sold under a fixed contract” means domestic natural gas sold by the producer under a contract, in effect on February 1, 1975, and at all times thereafter before such sale, under which the price for such gas cannot be adjusted to reflect to any extent the increase in liabilities of the seller for tax under this chapter by reason of the repeal of percentage depletion for gas. Price increases after February 1, 1975, shall be presumed to take increases in tax liabilities into account unless the taxpayer demonstrates to the contrary by clear and convincing evidence.

Id. (emphasis added). Notably, this definition placed a burden on the taxpayer to demonstrate that price increases made after February 1, 1975 were not instituted to reflect increases in the sellers’ tax liability. Id. One issue presented on appeal is whether Exxon’s 1975 sales of natural gas to HL & P were made under a “fixed contract,” and thus whether Exxon is entitled to invoke this exemption from the repeal of percentage depletion.

D. Procedural History of Exxon’s 1975 Refund Claim

Exxon timely filed its 1975 consolidated federal income tax return with the Internal Revenue Service (“IRS”) on September 15, 1976. In its 1975 tax return, Exxon claimed depletion deductions totaling $82,059,252, with respect to the 369 natural gas properties in issue. Virtually this entire sum was percentage depletion, as opposed to cost depletion. Upon audit, the Commissioner of the IRS disagreed with Exxon’s percentage depletion computations, and disallowed $66,676,098 of the 1975 percentage depletion deductions that Exxon had originally claimed with respect to the 369 natural gas properties in issue. As a consequence of adjustments mandated by the Commissioner, Exxon’s 1975 federal income tax liability increased by the sum of $32,004,527, which amount Exxon paid, plus assessed interest.

Thereafter, on June 5, 1990, Exxon filed a timely administrative claim for refund with the IRS, seeking a refund of tax allegedly overpaid for 1975. Exxon filed a subsequent claim for refund with the IRS on January 8, 1992. The Commissioner allowed none of Exxon’s 1975 refund claims relating to percentage depletion and, consequently, by a petition filed with the U.S. Court of Federal Claims on October 30, 1996, Exxon instituted this suit for refund.

In its January 7, 1998 opinion addressing the government’s summary judgment motion, the court determined that Exxon was entitled to calculate its deduction based upon an RMFP, and that a trial on the merits was necessary to determine an appropriate value. Whereas the government argued that the proper value for the RMFP was approximately $0.36 per thousand cubic feet (“Mcf’) of gas, Exxon sought an RMFP of approximately $0.76/ Mcf. After a three-week bench trial beginning on January 26, 1998, the court identified a set of 308 transactions involving the sale of raw gas in the immediate vicinity of the well, within the meaning of Treas. Reg. § 1.613-3(a), which it found yielded a representative price for sales of gas comparable to the gas at issue. The court found, based upon this “RMFP sample,” that the RMFP, with respect to Exxon’s production of “gas well gas” (representing 90.26% of the total volume of the disputed gas), was $0.6831/Mcf. Among its other decisions, the court also held that Exxon had failed to prove an RMFP with respect to its “casinghead gas,” representing 9.74% of the total volume of the gas. Moreover, the court found that none of the natural gas that Exxon sold during 1975 pursuant to its contract with HL & P was eligible for percentage depletion, on the ground that such gas failed to qualify as “natural gas sold under a fixed contract,” within the meaning of I.R.C. §§ 613A(b)(l)(B) and 613A(b)(2)(A).

On appeal, the government challenges the underlying legal conclusion of the trial court that Exxon is entitled to calculate its federal income tax deduction for the 1975 tax year based upon an RMFP. Because this issue is fundamental to the overall dispute, we will address the government’s cross-appeal first. Exxon’s appeal focuses on two narrower issues: (1) whether it is entitled to calculate its deduction for its casinghead gas based upon the RMFP; and (2) whether the gas it sold to HL & P was sold under a “fixed contract.”

II. Discussion

A. Is Exxon Entitled to Calculate its Deduction Based on an RMFP?

In its cross-appeal, the government argues that permitting Exxon to calculate its deduction based on an RMFP would be inconsistent with the 1975 amendments to the Tax Code. The government points out that, under the 1975 Act, market value sales ceased to qualify for percentage depletion. Because an RMFP is necessarily based on market prices, the government argues that it “makes no sense to include market value sales in the percentage depletion,” when such market-value sales would be ineligible for percentage depletion. Whether Exxon was entitled to claim the challenged deduction is a question of law, subject to de novo review. Melka Marine, Inc. v. United States, 187 F.3d 1370, 1374 (Fed.Cir.1999).

Both parties agree that the trial court’s reasoning was “straight-forward.” In its brief, the government recognizes that applying the plain language of the Tax Code and governing regulations leads to the trial court’s conclusion. The government states:

The court’s analysis was straight-forward. The court first noted that § 613A provided that percentage depletion under the fixed contract exception “shall be computed in accordance with section 613.” Section 613(a), it noted, provided that percentage depletion should be computed on the “gross income from the property.” “Gross income from the property,” in turn, was defined in Treas. Reg. § 613-3(a) to be an RMFP in those cases where an integrated producer, such as Exxon, did not sell its gas at the wellhead. Therefore, the lower court believed that this Court’s holding in Exxon I, which had allowed for an RMFP to exceed actual income, supported Exxon’s claim that it should be permitted to use a similarly-inflated RMFP in this case.

The government, however, argues that the plain language of the Tax Code and pertinent regulations does not control in this case. Although the government does not challenge the validity of Treas. Reg. § 613-3(a), it contends that applying this rule in this case would lead to “absurd results,” and would “thwart the obvious purpose” of the 1975 Act. See Commissioner v. Brown, 380 U.S. 563, 571, 85 S.Ct. 1162, 14 L.Ed.2d 75 (1965) (“[T]he courts, in interpreting a statute, have some scope for adopting a restricted rather than a literal or usual meaning of its words where acceptance of that meaning would lead to absurd results ... or would thwart the obvious purpose of the statute.”) (citations omitted); see also Public Citizen v. Department of Justice, 491 U.S. 440, 454-55, 109 S.Ct. 2558, 105 L.Ed.2d 377 (1989) (“Looking beyond the naked text for guidance is perfectly proper when the result it apparently decrees is difficult to fathom or where it seems inconsistent with Congress’ intention, since the plain-meaning rule is rather an axiom of experience than a rule of law, and does not preclude consideration of persuasive evidence if it exists.”) (citations omitted). The government complains that “in defining the ‘representative’ price for natural gas sold under a fixed contract, the lower court included in its computations sales that would not have qualified for percentage depletion.”

The parties agree that, under a mechanical application of Treas. Reg. § 1.613— 3(a), the disparity between the 1975 market price and Exxon’s actual sales prices permits Exxon to claim a deduction far in excess of what its gross income from the property reflects. The government’s cross-appeal basically constitutes a policy-based complaint that its own regulations produce “absurd results,” and that we should depart from the plain meaning of the Tax Code and governing regulations to correct this anomaly. In Exxon I, we considered a similar policy-based challenge to application of the RMFP for calculating Exxon’s 1974 deduction. Acknowledging that a straight-forward application of Treas. Reg. § 1.613-3(a) (1974) might frustrate the policy of federal income tax law to eliminate “competitive tax advantages [for integrated producers] over non-integrated producers,” we nonetheless refused to depart from the plain language of the Tax Code and the governing regulations. Exxon I, 88 F.3d at 975. We noted that “the Secretary at one time considered making such an amendment [to limit the RMFP to actual gross income], but that proposal was ultimately withdrawn.” Id. (citing 36 Fed.Reg. 19,256 (Oct. 1, 1971) and 33 Fed.Reg. 10,700 (July 26, 1968)). Declining to correct a perceived anomaly that the Secretary had refrained from fixing, we ruled that (“[u]ntil the Secretary imposes such a cap in the oil and gas area, we believe it is not within our judicial powers to legislate in his stead.”). Id.

The enactment of the 1975 Act does not mandate a different result. Despite having an opportunity to eliminate excessive deductions, Congress expressly allowed oil and gas producers to continue calculating their deductions based on an RMFP for oil and gas sold under fixed contracts. The House Report accompanying the bill states that “[w]here fixed price contracts exist, your committee believes that it would be unfair to apply the phaseout of depletion while the contract is in effect, and therefore the bill exempts gas sold in intrastate commerce under such a contract.” H.R.Rep. No. 93-1502 at 53 (1974). Congress was fully aware that the repeal of percentage depletion would apply initially only to 15-20% of all sales of gas, and that the amount of gas covered by the repeal of percentage depletion would increase only gradually as fixed-price contracts expired. See id. at 54. To the extent that pre 1975 law permitted gas producers like Exxon to claim windfall deductions, Congress deliberately chose to phase out this anomaly only gradually, and to permit gas producers like Exxon to continue to claim percentage depletion for their fixed price sales. As we held in Exxon I, it is not within our judicial powers to prohibit percentage depletion where Congress has condoned it. See Exxon I, 88 F.3d at 975.

To lend textual support to its policy-based argument, the government relies on Treas. Reg. § 1.613A-7(d) to argue that the sale of raw gas at the wellhead is not relevant for residue gas sold under fixed contracts. See Treas. Reg. § 1.613A-7(d). That regulation provides in pertinent part:

The term “natural gas sold under a fixed contract” means domestic natural gas sold by the producer ... under a contract, in effect on February 1, 1975 ... under which the price for the gas during such period cannot be adjusted to reflect to any extent the increase in liabilities of the seller for tax under chapter 1 of the Code by reason of the repeal of percentage depletion for gas.... Price increases after February 1, 1975, are presumed to take increases in tax liabilities into account unless the taxpayer demonstrates to the contrary by clear and convincing evidence.... For purposes of meeting the requirements of this paragraph, it is not necessary that the total gas production from a property qualify as “natural gas sold under a fixed contract,” for the determination of “natural gas sold under a fixed contract” is to be made with respect to each sale of each type of natural gas sold pursuant to each contract.

Treas. Reg. § 1.613A-7(d). This provision is excerpted from the “Definitions” section of the treasury regulations, and serves to define the statutory term “natural gas sold under a fixed contract.” The provision does not refer to “gross income from the property,” and says nothing about how the percentage depletion should be calculated. Although this regulation may have changed pre 1975 law by redefining what kinds of gas are eligible for percentage depletion, nothing in the regulation changes, or necessitates a change, in the method of computing the amount of percentage depletion for eligible gas. Thus, we find that Treas. Reg. § 1.613A-7(d) is owed no weight in determining the legality of Exxon’s claimed deductions.

Accordingly, we conclude that the plain language of the Tax Code and the pertinent regulations entitles Exxon to calculate its deduction based on an RMFP. Although these provisions arguably allow Exxon to claim an excessive deduction, it is not the province of this court to remedy anomalies in the tax laws that Congress and the Secretary have refrained from correcting.

B. Is Exxon Entitled to Claim Percentage Depletion for Its 1975 Sales of Casinghead Gas?

As noted above, the trial court ruled that Exxon’s casinghead gas must be excluded from the computation of the percentage depletion allowance because Exxon failed to prove the comparability of that gas to the gas sold in the transactions comprising the sample from which the RMFP was derived. Exxon argues that it has sufficiently demonstrated the comparability of its casinghead gas to the remainder of the gas it sold. Whether Exxon’s casinghead gas was equivalent to its gas well gas for tax purposes is a question of fact; accordingly, we review the trial court’s conclusions on this issue for clear error. Melka Marine, 187 F.3d at 1374.

Natural gas is generally classified in two categories: gas well gas, and casinghead gas. “Gas well gas” refers to gas that is found in a gaseous state at reservoir conditions. “Casinghead gas” refers to gas that was dissolved in oil at reservoir conditions but becomes gaseous at atmospheric pressure at the top, or “casinghead,” of an oil well. As stated in the expert report of Roland Pohler, submitted on behalf of Exxon, “[c]asinghead gas is generally richer in heavier hydrocarbons' than gas well gas, and it is generally produced at lower pressure.” The vast majority of gas sold by Exxon under the contracts at issue (90.26%), was gas well gas. Only 9.74% of the gas at issue was casinghead gas.

In order to be entitled to claim percentage depletion for its casinghead gas, Exxon bore the burden, by a preponderance of the evidence, to demonstrate that its cas-inghead gas was “reasonably or substantially similar” to the gas represented in the 308 transactions of the RMFP sample. Hugoton Prod. Co. v. United States, 161 Ct.Cl. 274, 315 F.2d 868, 871-72 (1963). Prior case law has set forth six factors to be weighed in determining whether a disputed quantity of gas is comparable to the gas of an RMFP sample: (1) total volume of gas available for sale; (2) proximity of the producer’s leases to pipelines; (3) hydrogen sulfide content; (4) BTU [“British thermal unit”] content; (5) delivery pressure of the gas; and (6) deliverability of the gas in terms of volume per day. Exxon Corp. v. United States, 33 Fed.Cl. 250, 270 (1995) (citing Hugoton, 315 F.2d at 894-95).

The RMFP study comprised sales of gas well gas, and did not contain sales figures relating to casinghead gas. Exxon’s expert, Pohler, explained at trial that the reason that casinghead gas from oil wells was not represented in the RMFP study is that a different reporting system is used to track sales of gas from oil wells, and that such data were not readily available. See Tr. 169 (“The information on individual oil wells is not available in the databases that are available to us.”). Obtaining such data, he stated, “would have been very difficult.” Id. Pohler opined, nonetheless, that “it could well be that the casinghead gas would command equally as good a price as the gas well gas.” Id. at 171. He based this conclusion on his reasoning that, although casinghead gas generally flows at a lower pressure than gas well gas, the casinghead gas generally has a higher BTU content, and that “[t]he BTU content would largely offset the lower pressure.” Id.

In addition to relying on this testimony by Pohler on the comparability of Exxon’s casinghead gas and gas well gas, Exxon argues that the evidence it submitted on the BTU content of its casinghead gas was sufficient to establish such comparability. Exxon notes that under prior industry accounting practices, when gas was sold on the basis of volume, it was necessary to consider all the factors recited in Hugoton to determine comparability. Exxon asserts, however, that by 1975 it had begun pricing gas on the basis of its BTU content, rather than on a volumetric basis. At trial, Exxon offered the testimony of several experts who stated that once gas was measured on the basis of its BTU-content, rather than its volume, “gas was gas,” and distinctions between casinghead gas and gas well gas became immaterial. Exxon contends that this change in pricing schemes obviates the need to consider the remainder of the Hugoton factors, and that the trial court erred in finding that the lack of evidence as to the other Hugo-ton factors (besides BTU content) constitutes a failure of proof.

The trial court gave full consideration to all these arguments. As to Pohler’s comparability analysis, the court noted that “Mr. Pohler admitted that casinghead gas and gas well gas are generally not comparable, in that casinghead gas is usually produced in smaller volumes, at lower pressures, and at lower rates of delivery, than gas well gas, and typically has a higher BTU content as well.” Absent clearer evidence on the comparability of the two kinds of gas, the court declined to extrapolate from its determinations for gas well gas and make conclusions concerning casinghead gas. Moreover, the court noted that, despite Exxon’s insistence that under BTU pricing, “gas was gas,” all the evidence submitted by the parties was presented in terms of volumetric pricing. The trial court acknowledged that Exxon’s cas-inghead gas might, indeed, be comparable to its gas well gas, but that Exxon simply failed to present sufficient evidence to carry its burden of persuasion. The court found that, although it may have been difficult for Exxon to incorporate data from oil wells into its RMFP study, “Admitted difficulty, however, is an insufficient response for failure of proof.”

Noting that over 90% of the gas at issue was gas well gas, the court found that Exxon had made a “tactical” decision to concentrate its litigation resources on gas well gas, and stated that “Exxon’s nearly singular focus on gas well gas, the bulk of the gas at issue, is understandable.” Noting the dearth of evidence on comparability of casinghead gas and gas well gas, the court concluded stating that “[hjaving made the decision to address the comparability of casinghead gas in cursory fashion, Exxon must bear the consequences of that decision.”

We find no clear error in the trial court’s conclusion. Little appears in the record to support Exxon’s contention that its casinghead gas was comparable to its gas well gas. Indeed, in response to the government’s straight-forward’ question as to whether the two kinds of gas were comparable, Pohler did not answer in the affirmative, but rather noted the distinctions between the two kinds of gas as to their BTU content and pressure characteristics. Tr. 170. Pohler’s testimony indicates that Exxon had access to additional data that might have demonstrated the comparability of Exxon’s casinghead gas, but that Exxon elected not to pursue this line of discovery.

Exxon may be correct that the industry’s shift in the early 1970s from volumetric pricing to BTU-based pricing may have rendered obsolete the multi-factored test applied in Hugoton and Exxon I. It may also be true, as Exxon suggests, that there may no longer be a need to treat casing-head gas distinctly from gas well gas for purposes of calculating an RMFP. However, as an appellate court with a very limited record to rely on, we are not in a position to decide whether to abandon the comparability factors recited in Hugoton and rely solely' on BTU content as the sole index of comparability. In future disputes concerning the comparability of different sources of gas, courts reviewing a more fully developed record might well determine that the multi-factored test recited in Hugoton has been obviated by the shift to BTU-based pricing, and that there need be no distinction drawn between casinghead gas and gas well gas. Today, we decline to make such a decision. Nor will we remand for further proceedings on this issue. This case concerns Exxon’s tax liability from 1975. After more than 25 years of litigation and a full and fair opportunity to demonstrate the comparability of its casinghead gas, it would be improper to give Exxon yet another bite at the apple. Because we discern no clear error in the trial court’s findings on this issue, we affirm its decision that Exxon failed to carry its burden of persuasion that its casing-head gas was comparable to its gas well gas.

C. Was the Gas Sold by Exxon to HL & P in 1975 “Natural Gas Sold Under a Fixed Contract”?

The final issue to be resolved on appeal is whether particular sales of natural gas in question constitute “gas sold under a fixed contract,” for the purposes of I.R.C. § 613A(b)(2)(A). Of the 18 contracts at issue in this case, the parties stipulated before trial that 16 of these contracts were “fixed price” and qualified for the exemption from the repeal of percentage depletion set forth in § 613A(b)(2)(A). The parties’ dispute as to the proper characterization of one other contract, entered into between Exxon and Southwestern Electric and Power Company (“SWEPCO”), was settled after trial. The sole contract remaining in dispute is between Exxon and HL&P.

The HL & P contract for the sale of natural gas, as originally entered into, had a 20 year duration, effective January 1, 1965. The parties amended the contract on May 29,1974 to incorporate therein two provisions that the trial court found disqualified the contract from being treated as a “fixed price” contract: the “Excess Royalty Reimbursement” clause, and the “Additional Gas” clause. These will be discussed in turn.

1. The Excess Royalty Reimbursement Clause

The “Excess Royalty Reimbursement,” or ERR, clause addressed Exxon’s concern that its profits under its fixed price contract with HL & P were being “squeezed” as Exxon’s royalty obligations to third parties, from whom Exxon purchased a portion of its gas, increased with the escalating market. On its face, the ERR provision allowed Exxon to pass through to HL & P no more than the increase in the cost of royalties (above previous levels) that Exxon paid to its royalty holders. Indeed, the contract states that HL & P would only be liable for its proportionate share of the royalties actually paid each month” by Exxon, (emphasis added). The ERR provision states, in full:

During the period beginning June 1, 1974 and ending December 31, 1987, Buyer agrees to pay its proportionate share of the royalties actually paid each month by Seller on gas entering Seller’s Exxon Gas System which are in excess of the royalties which would have been paid if such royalties had been paid at the same price received by Seller from Buyer for gas delivered hereunder. The aforesaid price received by Seller from Buyer shall be equal to the sum of the amounts paid under the provisions of Sections A and B of this Article III plus any amount paid pursuant to the provisions of Article IV hereof. Buyer’s proportionate share of excess royalties for which payment is due hereunder shall be computed each month based upon the ratio of the total volume of Seller’s deliveries of gas to Buyer hereunder to the total volume of gas (excluding gas transported for others) entering Seller’s Exxon Gas System. Seller shall, on or before the tenth (10th) day of each calendar month, render a statement to Buyer showing such share of excess royalties payable with respect to the gas delivered to Buyer during the second preceding calendar month. Except with respect to the billing date for excess royalty payments, all of the provisions of Article VI of the Contract shall apply to this obligation of Buyer.

Exxon’s position is that the ERR provision simply allowed Exxon to pass through its additional royalty costs to HL & P, and did not permit Exxon to increase its income to offset its tax liability. Accordingly, Exxon argues that the HL & P contract remained a “fixed price” contract for the purposes of § 613A(b)(2)(A).

The trial court took a skeptical view of this provision. The court fully recognized that the ERR clause could be a straightforward pass-through provision, and that the clause could be analogous to other permissible types of pass-through provisions specified in Treas. Reg. § 1.613A-7(c)(5). Under that regulation, contract provisions that permit price increases to offset “additional State and local real property or severance taxes, increases for additional operating costs (such as costs of secondary or tertiary process), ... [or] increases for additional drilling and related costs,” are permissible provisions that do not disqualify contracts from being treated as “fixed contracts.” Treas. Reg. § 1.613A-7(e)(5). Although the court agreed that the clause was facially equivalent to these permissible provisions, it determined that the ERR clause may have provided a mechanism for Exxon to recoup its increased tax liability, stating: “the court is firmly convinced that said ERR clause permitted Exxon to raise the price of its gas after February 1, 1975, such that Exxon could potentially have recovered a portion of its increased tax liabilities arising from the repeal of percentage depletion.”

The trial court noted that the first step in determining whether the HL & P contract was a “fixed contract” was to “examine the disputed price adjustment clauses in the HL & P ... contract[ ], in order to determine whether those clauses provide any mechanism whereby Exxon could legally raise the price of its natural gas in order to recoup, in whole or in part, its increased income tax liabilities arising from the repeal of percentage depletion.” Because § 613A(b)(2)(A) is to be narrowly construed, see INDOPCO, Inc. v. Commissioner, 503 U.S. 79, 84, 112 S.Ct. 1039, 117 L.Ed.2d 226 (1992) (holding that income tax deductions are a matter of legislative grace and are to be narrowly construed), and because the express language of that provision permits the exemption to apply only when the price of the contracted-for gas “cannot be adjusted to reflect to any extent the increase in liabilities of the seller for tax under this chapter,” I.R.C. § 613A(b)(2)(A) (1975) (emphasis added), the court imposed a high standard for determining whether Exxon could demonstrate that the HL & P contract was a “fixed contract.” The court stated that “if a plain reading of the disputed price adjustment clause, in ... the HL & P contract ..., raises any doubt whatsoever as to whether that clause permitted Exxon to raise the price of its gas after February 1, 1975, such that Exxon could potentially recover, in whole or in part, its increased income tax liabilities arising from the repeal of percentage depletion, the court must carefully address the factual merits of Exxon’s claim.” Exxon II, 45 Fed. Cl. at 739 (emphasis in original).

The court did, indeed, havé doubts as to whether the price increases could have been used by Exxon to offset its tax liability. The .basic premise underlying the court’s ruling is that the excess royalty reimbursements received by Exxon from HL & P were tied to the market price of gas. See id. at 741 (“Consequently, the excess royalty reimbursements that HL & P paid to Exxon during 1975 were also tied, at least in substantial part, to the current market price of natural gas.”). The court used this finding, which neither party disputes, to justify imposing on Exxon a dollar-for-dollar accounting burden to demonstrate that every dollar that was paid by HL & P to Exxon did indeed offset Exxon’s increased royalty obligations. Although Exxon proffered its worksheets from 1975 reflecting its month-by-month collections of excess royalty reimbursements from HL & P and its commensurate royalty obligations to individual royalty holders, the trial court found this eviden-tiary basis inadequate, holding that Exxon’s contract administrator, Glenn Whit-comb, lacked credibility to testify to the authenticity and meaning of the worksheets. Consequently, the court concluded that Exxon failed to carry its burden of proof to demonstrate that the HL & P contract qualified for the “fixed contract” exemption of § 613A(b)(2)(A).

We agree with the trial court that the first step in the present analysis is to determine whether the ERR clause provided any mechanism whereby Exxon could legally raise the price of its natural gas in order to recoup, in whole or in part, its increased income tax liabilities. Moreover, we agree that it is proper to consider whether a “plain reading of the disputed price adjustment clause ... raises any doubt” as to whether the clause permitted Exxon to recoup its tax liability. As the trial court noted, this is a matter of contract interpretation which presents a question of law. See Exxon II, 45 Fed.Cl. at 738. Accordingly, we review this question de novo. See H.B. Mac, Inc. v. United States, 153 F.3d 1338, 1345 (Fed.Cir.1998); P.J. Maffei Bldg. Wrecking Corp. v. United States, 732 F.2d 913, 916 (Fed.Cir.1984).

Upon a thorough review of the record, we discern no reason to suspect that Exxon was able to legally use the proceeds from the ERR clause to offset its tax liability. The plain language of the ERR provision recites that HL & P was required to pay only its “proportionate share of the royalties actually paid each month” by Exxon under its royalty obligations, (emphasis added). The express terms of the provision thus restrict the amount owed by HL & P to Exxon under the ERR clause to the exact dollar amount paid by Exxon to its royalty holders. On its face, this provision is a straight-forward pass-through clause. As the trial court acknowledged, such a clause is permitted under Treas. Reg. § 1.613A-7(c)(5). The trial court relied heavily on its observation that the amount of the royalty reimbursements was tied to the market price of gas. This undisputed conclusion, however, is by itself of no moment. Several of the price adjustment examples specifically permitted by the regulations (such as agreements to recoup the cost of local real property or severance taxes) similarly correlate with increases in the current market price of gas. See Treas. Reg. § 1.613A-7(c)(5). The rising amount of the royalty reimbursements might conceivably permit Exxon to recoup its tax liabilities, if, under a prospect raised in the government’s brief, Exxon withheld these reimbursements and failed to remit them to the royalty holders. But there was no evidence of such wrongdoing. We reject the notion advanced by the government that, in the present case, “Exxon had to prove that all of the price increase was passed on to its royalty holders.” Such a requirement would essentially require Exxon to prove, in the absence of any colorable suggestion that it withheld royalty reimbursements, that it did not defraud its royalty holders.

It is true that § 613A(b)(2)(A) provides that “[pjrice increases after February 1, 1975, shall be presumed to take increases in tax liabilities into account unless the taxpayer demonstrates to the contrary by clear and convincing evidence.” Accordingly, it was proper, as the trial court found, to require Exxon to prove by clear and convincing evidence that its price increases were applied to offset its increasing royalty obligations, and not its increasing tax liability. The regulations promulgated under § 613A(b)(2)(A) indicate that such a burden of proof may be carried by demonstrating that the challenged provision is the same as, or equivalent to, one or more of the examples recited in the regulation of “increases that are not attributable to the repeal of percentage depletion for gas.” Treas. Reg. § 1.613A-7(c)(5). The trial court concluded, and we agree, that the ERR clause is legally indistinguishable from the examples of permissible cost increases recited in Treas. Reg. § 1.613A 7(c)(5). And the trial court identified no accounting irregularities to suggest that Exxon did, in fact, direct the proceeds from the ERR clause to offset its increased tax liability. Indeed, even among the conjectures suggested by the government in its brief, we can identify no plausible theory, short of fraud, which would permit Exxon to recoup more from the ERR clause than the amount it was required to remit to its royalty holders. Accordingly, because the trial court made no findings of fact that the ERR clause did permit, or would plausibly permit, Exxon to recoup some of its increased tax liability due to the repeal of percentage depletion, we hold that the legal equivalency recognized by the trial court between the challenged clause and the permissible provisions recited in Treas. Reg. § 1.613A-7(c)(5) is sufficient to carry Exxon’s burden of persuasion that the HL & P contract is a “fixed contract” for the purposes of § 613A(b)(2)(A). We thus reverse the trial court’s determination that the ERR clause disqualified the HL & P contract from being a “fixed contract” under § 613A(b)(2)(A).

2. The Additional Gas Clause

The trial court provided an alternate ground for concluding that the HL & P contract is not a “fixed contract” for the purposes of § 613A(b)(2)(A). The court noted that the 1974 amendments to the HL & P contract introduced an “Additional Gas” clause into the contract, which provides:

D. Additional Gas: — During the period beginning June 1, 1974 and ending December 31, 1984 Seller, at its option, may from time to time tender gas in excess of the quantities Seller is obligated to make available to Buyer in accordance with the provisions of Article I hereof [ie., pertaining to the minimum quantity of gas deliverable to HL & P under the contract]. Excess gas so tendered by Seller shall hereinafter be identified as “Additional Gas”. In the event Buyer desires to accept Additional Gas from Seller, Buyer and Seller shall negotiate in good faith to agree on the going price for gas in the area where the gas is to be consumed. The price to be paid for such Additional Gas shall be said going price for gas. In addition, for each three thousand cubic feet of Additional Gas sold under the provisions of this Section D, one thousand cubic feet of gas scheduled to be sold concurrently in accordance with Section A of this Article III [ie. at 26 cents per MMBTU in 1976] shall instead be priced at the same price as the Additional Gas [ie., at the “going price for gas.”],

(emphasis added). The trial court stated that, in accordance with this provision, all that Exxon had to do under this clause, in order to raise the price of one Mcf of its gas, otherwise committed to HL & P at the regular 1975 contract price {ie., the price before the purported excess royalty reimbursement), to the “going price for gas in the area,” was to make available, sell, and deliver three Mcf of “additional gas” to HL & P. Under this clause, the trial court found that Exxon “could potentially have recovered a portion of its increased income tax liabilities arising from the repeal of percentage depletion.”

The trial court made no findings of fact on this point, and addressed the issue as one of contract interpretation. Accordingly, whether the Additional Gas clause disqualifies the HL & P contract from being a “fixed contract” is a question of law which we review de novo. See H.B. Mac, 153 F.3d at 1345; P.J. Maffei, 732 F.2d at 916.

As confirmed at oral argument, Exxon did not supply any Additional Gas to HL & P during the 1975 tax year. Exxon thus argues that the Additional Gas clause cannot disqualify the HL & P contract from being a “fixed contract,” because the clause was never invoked. We disagree with this assessment. Section 613A(b)(2)(A) does not define “natural gas sold under a fixed contract” in terms of whether a challenged clause was actually invoked; rather, it limits such contracts to agreements whereunder the price for gas “cannot be adjusted” to offset increased tax liabilities. I.R.C. § 613A(b)(2)(A) (1975). Thus, the question of whether the Additional Gas clause disqualifies the HL & P contract from the exemption from the repeal of percentage depletion focuses on whether the clause could permit Exxon to increase the price of the gas it originally contracted to sell, not whether Exxon actually increased the price of gas under the clause.

The literal language of the contract supports the trial court’s conclusion that Exxon was potentially able to receive increased prices for the gas it had originally committed to sell to HL & P. Under the clause, not only did HL & P agree to purchase the Additional Gas at market prices, but, upon exercise of its option to purchase Additional Gas, HL & P became obliged to pay market price for a portion of the gas already committed under the original contract: “[F]or each three thousand cubic feet of Additional Gas sold under the provisions of this Section D, one thousand cubic feet of gas scheduled to be sold concurrently in accordance with Section A of this Article III shall instead be priced at the same price as the Additional Gas.” The literal wording of the Additional Gas clause, which was adopted prior to the passage of the 1975 repeal legislation, and which thus was not drafted with a view toward the potential tax consequences under § 613A(b)(2)(A), is plainly contrary to the strictures of that provision.

A second, and apparently equivalent, way to interpret the provision suggests that the Additional Gas clause does not disqualify the HL & P contract from being treated as a “fixed contract.” To the extent that HL & P sought to purchase additional quantities of gas from Exxon, the Additional Gas clause can be regarded as permitting HL & P to purchase these quantities of gas at an above-market price. That is, the clause can be interpreted as imposing a surcharge above market price on the purchase of Additional Gas, while leaving the price of the originally-contracted for gas unaffected. The quantities of gas sold under the original and amended contracts, and the money obtained under the contracts, of course are fungible, and whether to attribute the “surcharge” solely to the Additional Gas obtained, or to allocate the “surcharge” to the originally-contracted for gas, is somewhat of an arbitrary classification.

In favor of Exxon, the Additional Gas clause was to be invoked, and the price increases triggered, only if HL & P “desires to accept” the Additional Gas. Thus HL & P, and not Exxon, was in control as to whether the higher prices recited in the Additional Gas clause would apply, and whether the “surcharge” for the Additional Gas would be assessed. In this light, the Additional Gas clause did not provide a method for Exxon to increase the price of the originally-contracted for gas; rather, it provided HL & P a means to obtain quantities of additional gas beyond originally-contracted for amounts, albeit at a surcharge above market price. Under such an interpretation, the price of gas under the original contract, for the original quantity of gas, remains “fixed,” and the HL & P contract would remain qualified for percentage depletion under § 613A(b)(2)(A).

That HL & P, and not Exxon, controlled whether the Additional Gas clause would be invoked is dispositive of this issue. Congress clearly intended to maintain tax benefits for those companies who lacked the ability to increase the prices they were obtaining for gas under long-term fixed-price contracts. See H.R.Rep. No. 93-1502, at 53 (1974) (“Where fixed price contracts exist, your committee believes that it would be unfair to apply the phaseout of depletion while the contract is in effect, and therefore the bill exempts gas sold in intrastate commerce under such a contract.”). Under the Additional Gas clause, it was HL & P alone that had the power to raise the price. The clause provided no means for Exxon to exercise control over whether HL & P would purchase the Additional Gas. Because the price increases could not be invoked by Exxon, but only by its customer, we conclude that the Additional Gas clause is more closely akin to imposing an above-market surcharge on the purchase of Additional Gas, rather than adjusting the price of gas contracted for under the original agreement. We thus hold that the trial court erred in ruling that the HL & P contract was disqualified from being classified as a “fixed contract” for the purposes of § 613A(b)(2)(A).

III. Conclusion

Because the plain language of the Tax Code and governing regulations entitles Exxon to calculate its federal income tax deduction based on an RMFP, we affirm the trial court’s ruling against the government on its cross-appeal. Moreover, because we find no clear error in the trial court’s finding that Exxon failed to carry its burden of demonstrating that its cas-inghead gas was equivalent to the gas of the RMFP sample, we affirm the trial court’s judgment as to the casinghead gas issue. However, we conclude that the ERR provision of the HL & P contract was legally equivalent to the permissible price increase provisions recited in Treas. Reg. § 1.618A-7(c)(5). Moreover, we conclude that the Additional Gas clause does not disqualify the HL & P contract from treatment as a “fixed contract” under § 613A(b)(2)(A) because HL & P retained control over whether the price increases would apply and therefore the taxpayer, Exxon, could not cause a price increase. Accordingly, we reverse the trial court’s judgment as to the HL & P contract. We remand to the trial court with instructions to compute the tax refund owed to Exxon in light of our holding that the gas sold by Exxon to HL & P in 1975 constitutes “natural gas sold under a fixed contract,” pursuant to I.R.C. § 613A(b)(2)(A).

AFFIRMED IN PART, REVERSED IN PART, and REMANDED

COSTS

Each party to bear its own costs.