Exxon Corp. v. United States

OPINION

REGINALD W. GIBSON, Senior Judge.

Table of Contents

Subject Page

INTRODUCTION........................................................ 588

BACKGROUND ......................................................... 588

I. Exxon’s 1975 Sales Of Natural Gas Pursuant To Long-Term Contracts..... 588

II. The Statutory Allowance For Percentage Depletion — Applicable Law...... 590

A. Introduction....................................:................ 590

B. Percentage Depletion Under Pre-1975 Law......................... 591

C. Percentage Depletion Under Post-1974 Law ........................ 594

III. Procedural History Of Exxon’s 1975 Refund Claim....................... 595

*587 IV. Evidence Presented At Trial.......................................... 597

DISCUSSION ........................................................... 604

I. Relevant Market Area In 1975 ........................................ 605

A. The Natural Gas Industry In The Texas Gulf Coast/East Texas Region In 1975 ......................................................... 606

B. Contentions Of The Parties ....................................... 609

C. Discussion...................................................... 610

1. Collateral Estoppel........................................... 610

2. Gas Comparability Determination.............................. 615

II. Comparability Of Gas................................................ 620

A. Background..................................................... 620

B. Contentions Of The Parties ....................................... 621

C. Discussion...................................................... 622

1. Collateral Estoppel........................................... 622

2. Determination Of The Relevant Market Area In 1975 ............. 624

a. Volume Available for Sale................................... 626

b. Delivery or Rock Pressure.................................. 627

e. Deliverability of Producer’s Wells............................ 628

d. Location and Proximity of Producer’s Lease(s) to Gas Pipelines 628

e. Hydrogen Sulfide Content.................................. 631

f. Btu Content .............................................. 632

3. Gas Comparability — Conclusion................................ 636

III. Identification Of Transactions Qualifying For Inclusion In The RMFP Sample............................................................. 637

A. Operative Definition Of A “Wellhead Sale”.......................... 637

B. Transportation Of The Gas Prior To Sale ........................... 643

1. Contentions Of The Parties.................................... 643

2. De Jure Account 800 Transactions v. De Facto Account 800 Transactions ........................................................ 648

C. Collateral Estoppel And Plaintiffs On-The-Lease Criterion........... 652

D. Legal Foundations Of Plaintiffs On-The-Lease Criterion ............. 660

E. Evidentiary Foundations Of Plaintiffs On-The-Lease Criterion........ 668

F. Transportation, “On The Lease” Or Not, Adds Value To Natural Gas 675

G. Summary — Validity Of Exxon’s On-The-Lease Criterion.............. 683

H. Transactions Involving Reservations Of Gas Processing Rights To The Seller.......................................................... 687

1. Background................................................. 687

2. Contentions Of The Parties.................................... 688

3. Discussion................................................... 689

I. Transactions Qualifying For Inclusion In The RMFP Computation..... 695

1. Background................................................. 695

2. Selection Of The RMFP Sample................................ 699

3. Comparison Of The Court’s RMFP Sample To Alternate Samples 711

4. Adjustments For Costs Of Compression Prior To Sale ............ 715

5. Adjustments For Costs Of Dehydration Prior To Sale............. 726

6. Conclusion — Compression And Dehydration Adjustments.......... 730

J. Determination Of The RMFP — Conclusion.......................... 731

IV. Qualification Of The HL & P And SWEPCO Contracts As “Fixed Contracts” ............................................................. 732

A. Statutory Background............................................ 732

B. Factual Background.............................................. 733

1. The HL & P Contract......................................... 733

2. The SWEPCO Contract....................................... 734

C. Contentions Of The Parties ....................................... 737

D. Discussion...................................................... 738

1. The HL & P Contract......................................... 740

*588 [[Image here]]

CONCLUSION .......................................................... 748

APPENDIX A — RMFP Computation....................................... 749

INTRODUCTION

This federal income tax refund case is pending before the court following a trial on the merits held in Washington, D.C., from January 26 through February 13, 1998. Plaintiff, Exxon Corporation and its consolidated subsidiaries (hereinafter “Exxon”), seeks to recover the sum of $172,584,915.83, consisting of Exxon’s alleged overpayment of federal corporate income taxes in the amount of $57,704,527.00 respecting its taxable year ended December 31, 1975, and assessed interest in the amount of $114,880,388.83, plus additional interest thereon as provided by law. The controversy at bar pertains to the amount of Exxon’s claimed entitlement to percentage depletion deductions, pursuant to Internal Revenue Code §§ 611, 613, and 613A, 1 relative to certain sales of natural gas that Exxon produced along the Texas Gulf Coast and in the East Texas region during the taxable year 1975. By this opinion, we decide two primary questions. First, the court must determine what “representative market or field price” (RMFP), if any, within the meaning of Treas. Reg. § 1.613-3 (a), must be used to calculate the allowance for percentage depletion with respect to Exxon’s 1975 gas production in issue. Second, the court must decide whether the natural gas sold by Exxon during 1975, pursuant to its contracts with Houston Lighting & Power Company (HL & P) and Southwestern Electric and Power Company (SWEPCO), was “natural gas sold under a fixed contract,” within the meaning of §§ 613A(b)(1)(B) and 613A(b)(2)(A).

Having thoroughly examined the trial record, we hold, inter alia, that for purposes of calculating Exxon’s 1975 allowance for percentage depletion, the RMFP is $0.6831 per each thousand cubic feet (Mcf) of natural gas in issue that is eligible for percentage depletion. As to the second issue presented, we hold that Exxon has failed to prove, by clear and convincing evidence, the quantum of proof required by § 613A(b)(2)(A), that its contract with HL & P qualified as a “fixed contract,” but has proven that the SWEPCO contract did so qualify.

BACKGROUND

I. Exxon’s 1975 Sales Of Natural Gas Pursuant To Long-Term Contracts

During its taxable year 1975, Exxon produced raw natural gas from 369 properties situated along the Texas Gulf Coast and within East Texas. 2 Then, as now, Exxon was a fully integrated oil and gas company engaged in the exploration and production of crude oil and natural gas, and in the refining, transportation, purchase and sale of oil, gas, and products made therefrom. At issue are Exxon’s 1975 sales of natural gas to 18 customers, made pursuant to long-term contracts entered into between 1955 and 1972. 3 *589 Sixteen (16) of these contracts, entered into with industrial consumers of natural gas, were referred to by Exxon as its Texas Industrial Commitment (TIC), whereas the remaining two customers were pipeline companies engaged in the intrastate purchase, transportation and resale of natural gas. In 1975, Exxon delivered gas from the 369 properties in issue to the aforesaid 18 customers by means of its own gas pipeline transmission system, the Exxon Gas System (EGS). Exxon began construction of EGS in the 1930s, in order to connect its large natural gas reserves in the Texas Gulf Coast/East Texas region to the industrialized markets located along the northeastern section of the Texas Gulf Coast, in the general vicinity of, and between, the cities of Houston, Beaumont, and Port Arthur, Texas. By 1975, EGS extended 1,500 miles throughout the Texas Gulf Coast/East Texas region, and consisted of two primary, interconnected transmission pipelines—one running from a point near Corpus Christi, a coastal city in South Texas, northward to a point near the city of Tyler in Northeast Texas, and the other running eastward from Houston to Port Arthur, near the Louisiana border. Generally, the flow of gas within EGS converged upon the Houston-Port Arthur industrial corridor, meaning that Exxon gas produced in the vicinity of Corpus Christi flowed northward, whereas gas from East Texas flowed southward. Most of the foregoing has, of course, been explicated in connection with the prior litigation over Exxon’s percentage depletion deduction for its taxable year 1974. See Exxon Corp. v. United States, 33 Fed.Cl. 250, 262 (1995), 4 rev’d on unrelated grounds, 88 F.3d 968 (Fed.Cir.1996), ce rt. denied, 520 U.S. 1119 , 117 S.Ct. 1252 , 137 L.Ed.2d 332 (1997) (hereinafter, “Exxon I ”).

The vast majority of the gas sold by Exxon during 1975, pursuant to the 18 long-term contracts in issue, entered EGS after such gas was processed in one of Exxon’s eight gas processing plants. Natural gas is composed principally of hydrocarbons, chemical compounds that contain carbon atoms and hydrogen atoms. Methane is the simplest, lightest hydrocarbon, consisting of a molecule with one carbon atom and four hydrogen atoms, and, in terms of volume, is typically the largest constituent of raw natural gas. Natural gas processing plants extract certain liquefiable hydrocarbons, or so-called “natural gas liquids,” from the raw gas wellstream. Such natural gas liquids include ethane, propane, butanes, and heavier hydrocarbons (pentanes, hexane, heptane, octane, nonnane and decane) commonly referred to as “natural gasoline.” 5 After the natural gas liquids have been extracted, the remaining natural gas consists primarily of methane, in proportions exceeding 90%, and is referred to as “residue gas.” It is this residue gas that is transported by pipeline and burned as fuel by industrial users or consumers, i.e., in a gas stove or furnace in the home. See also Exxon I, 33 Fed.Cl. at 256-58 (similar findings, relative to 1974, as to all of the foregoing).

About two-thirds of the gas at issue came from Exxon’s King Ranch gas plant, located southwest of Corpus Christi in Kleberg County, Texas. Roughly another 17% of the gas at issue was processed in Exxon’s Katy gas plant, located a few miles west of Houston in Waller County. Exxon’s other four gas plants in the Texas Gulf Coast area, and *590 the respective proportions of the gas in issue processed in each such plant, were: (i) the Anahuac plant, located east of Houston in Chambers County (approx. 4.5%); (ii) the Pledger plant, located southwest of Houston, and northeast of Corpus Christi, in Brazoria County (approx. 3.7%); (iii) the Clear Lake plant, located a few miles southeast of Houston in Harris County (approx. 2.4%); and (iv) the Lovell Lake plant, located east of Houston, and south of Beaumont, in Jefferson County (0.9%). Thus, in total, Exxon’s six gas plants along the Texas Gulf Coast processed about 95.3% of the gas at issue. In addition, about 1.1% of the gas at issue was processed at Exxon’s two gas plants in the East Texas area, located to the north of Houston in the general vicinity of the city of Longview: (i) the Hawkins plant in Wood County (1.0%); and (ii) the East Texas plant in Rusk County (0.1%). The remaining 3.6% of the gas at issue was not processed in an Exxon gas plant, and came primarily from the Trawick Field in East Texas, located to the north of Houston, but south of the Hawkins and East Texas gas plants, in Nacogdo-ches County.

Because Exxon transported all of the gas in issue away from the related 369 properties, and processed most of that gas as well, prior to sale, Exxon’s percentage depletion deduction for the taxable year 1975 must be computed as if Exxon had sold its gas at a “representative market or field price” (RMFP), computed in accordance with Treas. Reg. § 1.613-3 (a). 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 . Thus, the discussion now turns to the statutory provisions, Treasury regulations, and case law that govern the computation of the allowance for percentage depletion and, specifically, the determination of the RMFP.

II. The Statutory Allowance For Percentage Depletion — Applicable Law

A. Introduction

Depletion “reflects the exhaustion of a natural resource, such as natural gas, as a result of its severance from the earth.” Exxon Corp. v. United States, 40 Fed.Cl. 73, 76 (1998) (opinion denying defendant’s pre-trial motion for summary judgment) (citing Exxon I, 33 Fed.Cl. at 252 ). In 1975, the basic Code provision authorizing an income tax deduction for natural gas depletion stated, in relevant part:

In the case of mines, oil and gas wells, other natural deposits, and timber, there shall be allowed as a deduction in computing taxable income a reasonable allowance for depletion and for depreciation of improvements, according to the peculiar conditions in each case; such reasonable allowance in all cases to be made under regulations prescribed by the Secretary or his delegate.

I.R.C. § 611(a). Pursuant thereto, the Code specifies two methods by which the taxpayer may compute its depletion allowance — -cost depletion and percentage depletion. As to the substantive distinction between those two methods, the Supreme Court has observed:

Congress has allowed holders of economic interests in mineral deposits, including oil and gas wells, to deduct from their taxable incomes the larger of two depletion allowances: cost or percentage. Under cost depletion, taxpayers amortize the cost of their wells over their total productive lives. Under percentage depletion, taxpayers deduct a statutorily specified percentage of the “gross income” generated from the property, irrespective of actual costs incurred ____ 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.

Commissioner v. Engle, 464 U.S. 206, 208-09 , 104 S.Ct. 597 , 78 L.Ed.2d 420 (1984). Cost depletion, not in controversy here, produces a limited and predictable stream of annual tax deductions, over the productive life of a natural gas property, in that it merely recovers the taxpayer’s actual capital investment, or cost basis, in the property. Exxon, 40 Fed.Cl. at 76 & n. 6 (citing Engle, 464 U.S. at 209 n. 2, 104 S.Ct. 597 ; Exxon I, 33 Fed.Cl. at 252 ). Percentage depletion, on the other hand, may yield deductions significantly exceeding the taxpayer’s investment in *591 the property, for it is based upon the income generated by the property throughout its productive life, rather than the cost of such property. Exxon, 40 Fed.Cl. at 76 . Congress’ intention, in structuring the statutory allowance for percentage depletion in the aforesaid manner, was to provide taxpayers an economic incentive to engage in the costly venture of oil and gas exploration and production, thereby increasing the nation’s energy resources. Id. at 77 (citing authorities).

B. Percentage Depletion Under Pre-1975 Law

Our examination of the law governing Exxon’s claimed entitlement to a percentage depletion deduction, with respect to the taxable year 1975, must necessarily begin with the statutory percentage depletion framework that was in place prior to 1975. As in effect for taxable years ending on or before December 31, 1974, the operative provision of the Code, relative to the allowance for percentage depletion, stated as follows, in pertinent part:

(a) General Rule.—In the ease 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) 22percent—

(A) oil and gas wells [.]

§§ 613(a), (b)(1)(A) (1974) (emphasis added). Thus, “prior to 1975, the annual allowance for percentage depletion equalled 22 percent of the taxpayer’s gross income from sales of natural gas extracted from the property, subject to certain limitations not pertinent here.” Exxon, 40 Fed.Cl. at 76 . 6 The Code does not, however, prescribe a definition of the pivotal term, “the gross income from the property.” Instead, Congress directed that the determination of a taxpayer’s entitlement to a depletion deduction, including the allowance for percentage depletion, is “in all cases to be made under regulations prescribed by the Secretary.” § 611(a) (emphasis added).

Pursuant to the foregoing delegation of rulemaking authority, the Secretary promulgated a Treasury Regulation that provides, in relevant part:

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 to 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 price [RMFP] of the oil or gas before conversion or transportation.

Treas. Reg. § 1.613-3 (a) (emphasis added). This Regulation, including its substantially identical predecessors, has been continuously in effect since 1922. Exxon, 40 Fed.Cl. at 89 n. 25 (citing authorities as to historical origins of RMFP method). Moreover, its validity is unquestioned, as demonstrated by numerous decisions in which the courts have repeatedly sustained Treas.Reg. § 1.613-3(a) as a permissible exercise of the Secretary’s delegated authority to promulgate rules governing every aspect of depletion determinations. See, e.g., Exxon I, 88 F.3d at 974-76, 980 , 33 Fed.Cl. at 265-69 ; Panhandle Eastern Pipe Line Co. v. United States, 187 Ct.Cl. 129 , 408 F.2d 690 (1969); Hugoton Production Co. v. United States, 172 Ct.Cl. 444 , 349 F.2d 418 (1965) (“Hugoton II”); Hugoton Production Co. v. United States, *592 161 Ct.Cl. 274 , 315 F.2d 868 (1963) (“Hugoton I ”); Exxon Corp. v. Commissioner, 102 T.C. 721 , 1994 WL 243435 (1994) (percentage depletion issue similar to that presented here at bar, but relating to Exxon’s 1979 taxable year); Shamrock Oil & Gas Corp. v. Commissioner, 35 T.C. 979 , 1961 WL 1273 (1961), aff'd, 346 F.2d 377 (5th Cir.), cert. denied, 382 U.S. 892 , 86 S.Ct. 185 , 15 L.Ed.2d 149 (1965). See also United States v. Cannelton Sewer Pipe Co., 364 U.S. 76 , 80 S.Ct. 1581 , 4 L.Ed.2d 1581 (1960) (sustaining the RMFP method in the context of percentage depletion allowable to integrated producers of hard minerals). 7

Conceptually, the fundamental purpose of Treas. Reg. § 1.613-3 (a) is easy to grasp. Early percentage depletion cases uniformly recognized that an integrated producer’s percentage depletion allowance must be computed upon the value of the natural gas “at the mouth of the well.” Signal Gasoline Corp. v. Commissioner, 77 F.2d 728, 730 (9th Cir.1935), ce rt. denied, 296 U.S. 657 , 56 S.Ct. 383 , 80 L.Ed. 468 (1936); Greensboro Gas Co. v. Commissioner, 79 F.2d 701, 701 (3d Cir.), cert. denied, 296 U.S. 639 , 56 S.Ct. 172 , 80 L.Ed. 454 (1935); Consumers Natural Gas Co. v. Commissioner, 78 F.2d 161, 163 (2d Cir.), cert. denied, 296 U.S. 634 , 56 S.Ct. 157 , 80 L.Ed. 451 (1935). This is so, as we have previously observed, “because integrated producers frequently transport and process gas after extraction and prior to sale, whereas nonintegrated producers commonly sell unprocessed gas near the wellhead.” Exxon, 40 Fed.Cl. at 77 (citing Exxon I, 88 F.3d at 970 , 33 Fed.Cl. at 252 ). From the viewpoint of a prospective buyer of gas, such transportation and processing add value to the gas, of course, because the integrated producer, not the buyer, bears the associated costs. Therefore, “integrated producers tend to sell natural gas at prices higher than those charged by nonintegrated producers and, concomitantly, integrated producers realize more gross income per unit of natural gas sold.” Id. (citing Exxon I, 88 F.3d at 970 , 33 Fed.Cl. at 252 ). See also Panhandle, 187 Ct.Cl. at 143 , 408 F.2d at 700 ; Hugoton I, 161 Ct.Cl. at 277 , 315 F.2d at 869 (to same effect). Given the aforementioned considerations, the purpose of Treas. Reg. § 1.613-3 (a) is clearly to equalize the basis of entitlement:

Treas.Reg. § 1.613-3(a) is designed to maintain integrated and nonintegrated producers on an equal competitive footing, by requiring that the integrated producer’s “gross income from the property” exclude post-extraction value added to the natural gas.... Thus, the RMFP calculation aims to ensure that an integrated producer is entitled to no greater percentage depletion deduction, for any given quantity of natural gas extracted, than its nonintegrated competitors.

Exxon, 40 Fed.Cl. at 77 (citing Exxon I, 88 F.3d at 975-76 ); Panhandle, 187 Ct.Cl. at 144 , 408 F.2d at 700 ; Hugoton II, 172 Ct.Cl. at 455 , 349 F.2d at 425 ; Hugoton I, 161 Ct.Cl. at 277 , 315 F.2d at 869 . In short, as the Federal Circuit has emphasized, “the fundamental goal of the [RMFP] calculation is to arrive at a price that is representative of the price which would be realized by noninte-grated producers.” Exxon I, 88 F.3d at 976 (emphasis in original).

Regarding the mechanics of the RMFP determination, it is well settled that 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 (citing Panhandle, 408 F.2d at 703 ; Hugoton I, 315 F.2d at 877 ). So defined, 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 *593 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). Each of these three elements (including certain sub-elements thereof) is the subject of detailed legal and factual analysis herein, infra.

Beyond the foregoing specifics, Exxon I and the other binding RMFP precedents above, 8 all decided under the pre-1975 law of percentage depletion, delineate two additional general principles. First, as a matter of law, it is of no consequence that the RMFP exceeds, even substantially, the taxpayer’s actual gross income from its pertinent sales of natural gas. Exxon I, 88 F.3d at 976 . The percentage depletion controversy in Exxon I centered upon Exxon’s sales of gas, at prices well below the prevailing market price in 1974, pursuant to its 17 long-term TIC contracts then in force (16 of which are also at issue here at bar in relation to 1975). Id. at 970 , 33 Fed.Cl. at 262 . Despite the fact that the average delivery price of the gas sold under the TIC contracts was only $0.23 per thousand cubic feet (Mcf), inclusive of processing and transportation by Exxon, the Federal Circuit held that Exxon was entitled to base its 1974 percentage depletion deduction on a RMFP of $0.39/Mef. Exxon I, 88 F.3d at 970, 979 . Further, in reversing the decision below, 33 Fed.Cl. at 283-84 , the Federal Circuit held that the trial court may not, pursuant to an independent reasonableness analysis, reject an otherwise valid RMFP. Id. at 980-81. On the contrary, instructed the Federal Circuit, once an RMFP is established in accordance with Treas.Reg. § 1.613-3(a) and the relevant precedents, it “is per se reasonable, absent a challenge to the regulation itself.” Id. at 980. 9

Second, the RMFP determination does not demand hypertechnical precision. Rather, pursuant to Treas.Reg. § 1.613-3(a), “the RMFP is employed as an inexact, simplified means of calculating an integrated producer’s [percentage] depletion deduction.” Exxon I, 88 F.3d at 976 . The characteristic inexactitude of the RMFP computation stems from the fact that its objective is not the determination of an integrated producer’s “actual gross income, a known figure,” but rather, “a constructive gross income derived from the average wellhead market price for similar gas.” Id. at 970 (emphasis added). Due to the RMFP method’s “inherent uncertainties,” Hugoton I, 161 Ct.Cl. at 282 , 315 F.2d at 872 , courts consistently acknowledge that the “calculation of the RMFP is a difficult and sometimes onerous task.” Exxon I, 88 F.3d at 976 . 10 However, “[i]f evidence of substantially comparable sales can be shown, ... the price so derived is not to be disregarded merely because it is an approximation. ” Hugoton I, 161 Ct.Cl. at 281 , 315 F.2d at 872 (emphasis added). Therefore, the precedents also instruct that the imprecision of the RMFP method can be ameliorated by using a sample of transactions that is “sufficiently large and diverse enough to discount variations and offset errors.” Panhandle, 187 Ct.Cl. at 152 , 408 F.2d at 704 . What is more, “larger sampling should provide greater assurance that the price derived is in fact representative.” Hugoton I, 161 Ct.Cl. at 289 , 315 F.2d at 877 (emphasis added), quoted with approval in Exxon I, 88 F.3d at 976. See also id. at 977-78 (emphasizing “the goal of maximizing the number of transactions *594 included” in the RMFP sample). Taking our cue from the aforementioned authorities, we employ the term “RMFP sample” herein, generally, to describe any group of transactions that is under consideration for the RMFP computation.

A great deal more remains to be said about the RMFP, of course, regarding the particulars of the relevant market area determination, the gas comparability inquiry, and the operative definition of a wellhead sale, but each of those matters is best examined in light of the evidence pertinent thereto, and shall be addressed below in due course. Thus, having outlined the pre -1975 law of percentage depletion, as it applied to an integrated producer of natural gas, the discussion now turns to the legislative changes brought about by the Tax Reduction Act of 1975.

C. Percentage Depletion Under PosP-197h Law

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 ; Exxon, 40 Fed.Cl. at 78 . Consequently, with the enactment of the Tax Reduction Act of 1975, Pub.L. No. 94-12, § 501 , 89 Stat. 26 , 47-53 (March 29, 1975), Congress repealed the allowance for percentage depletion, as it applied to the major integrated oil and gas companies, subject only to certain narrow exceptions. Effective January 1, 1975, with application to taxable years ending after December 31, 1974, newly enacted I.R.C. § 613A provided:

SEC. 613A. LIMITATIONS ON PERCENTAGE DEPLETION FOR OIL AND GAS.

(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 6IS [ie., the allowance for percentage depletion].

(b) EXEMPTION FOR CERTAIN DOMESTIC GAS WELLS.—

(1) IN GENERAL.—The allowance for depletion under section 611 shall be computed in accordance with section 6IS with respect to—

(B) natural gas sold under a fixed con- tract____

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) (emphasis added). In furtherance of the general repeal of percentage depletion for oil and gas, pursuant to § 613A(a), supra, the 1975 Act also made certain correlative amendments to § 613 of the Code, two of which we note here. First, the 1975 Act struck out former § 613(b)(1)(A), which listed “oil and gas wells” among the mineral properties qualifying for percentage depletion at a rate of 22 percent. Pub.L. No. 94-12, § 501 (b), 89 Stat. 53 . Second, consistent with the repeal-er in § 613A(a), the Act amended § 613(d) to state: “Except as provided in section 613A, in the case of any oil or gas well, the allowance for percentage depletion shall be computed without reference to this section.” Id.

Here at bar, Exxon contends that its 1975 sales of gas under the 18 long-term contracts in issue (i.e., the 16 TIC contracts and the two contracts with pipeline customers) qualify for percentage depletion under § 613A(b)(1)(B), supra, which excepted certain “natural gas sold under a fixed contract” from the repeal of percentage depletion. In short, whereas all of Exxon’s 1974 natural gas production qualified for percentage depletion in that taxable year, only the gas that Exxon sold pursuant to “fixed contracts” so qualified in 1975. As in effect during the year 1975, the Code defined such a “fixed contract” as follows:

The term “natural gas sold under a fixed contract” means domestic natural gas sold *595 by the producer under a contract, in effect on February 1, 1975, and at all times thereafter before each 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. 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.

§ 613A(b)(2)(A) (1975) (emphasis added). The Government concedes that 16 of the 18 long-term contracts in issue met the requirements of the foregoing “fixed contract” exception in 1975. Thus, only the qualification of Exxon’s long-term contracts with Houston Lighting & Power Company (HL & P) and Southwestern Electric Power Company (SWEPCO) is contested here at bar. Because, at the threshold, the RMFP determination is our immediate concern, further consideration of whether the HL & P and SWEPCO contracts were “fixed contracts,” within the meaning of § 613A(b)(2)(A), supra, is deferred to the penultimate section of this opinion.

We conclude this introductory overview of the post-1974 law of percentage depletion, as applicable to integrated producers of natural gas, by noting that in May of 1977, the Secretary issued extensive Treasury Regulations under § 613A, thereby effecting the administrative implementation of the repeal of percentage depletion, including the implementation of the fixed contract exception thereto. T.D. 7487, 42 Fed.Reg. 24,264 (May 13, 1977); Treas.Reg. §§ 1.613A-0 through I. 613A-7. Yet, even in the midst of this comprehensive overhaul of the percentage depletion regulations, Treas.Reg. § 1.613-3(a)— prescribing the RMFP computation as the exclusive basis for determining an integrated natural gas producer’s “gross income from the property” for percentage depletion purposes — was retained unaltered in the Code of Federal Regulations. Exxon, 40 Fed.Cl. at 80, 89 . The implications of the continued efficacy of Treas.Reg. § 1.613-3(a), with respect to the case at bar, have been a fertile source of controversy.

Before turning to the merits respecting the determination of the RMFP, however, clarity of presentation requires that we address two additional background aspects of this litigation. First, we briefly recount the procedural history of Exxon’s refund claim for its taxable year 1975, up to and including the court’s denial of the Government’s pre-trial motion for summary judgment. Thereafter, the court shall explicate, at somewhat greater length, the nature and extent of the evi-dentiary record compiled at trial.

III. Procedural History Of Exxon’s 1975 Refund Claim

Exxon timely filed its 1975 consolidated federal income tax return with the Internal Revenue Service 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 all of this sum was percentage depletion, as opposed to cost depletion. 11 Upon audit, the Commissioner 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. The Commissioner’s audit adjustment had two components, one pertaining to January of 1975 and the other relating to the last eleven months of 1975. First, the Commissioner disallowed the portion of Exxon’s claimed depletable gross income from the property, with respect to gas produced from the 369 properties in issue prior to February 1, 1975, that exceeded Exxon’s actual sales revenues for such gas, net of transportation costs and royalties paid by Exxon. Second, the Commissioner disallowed all of Exxon’s claimed depletable gross income from the property with respect to gas from the 369 properties that was produced on or after February 1, 1975, and transported through EGS prior to sale. As a consequence of the foregoing adjustments, Exxon’s 1975 federal income tax liability increased by *596 the sum of $32,004,527. Exxon paid the $32,-004,527 tax deficiency, plus assessed interest.

Thereafter, on June 5, 1990, Exxon filed a timely administrative claim for refund (Form 1120X) with the IRS, seeking a refund of tax allegedly overpaid for 1975, in the sum of $117,787,209. Included within the foregoing sum were refund claims of $32,004,527 and $11,790,788, relating to Exxon’s claimed entitlement to a percentage depletion deduction for natural gas sold in 1975, pursuant to contracts purported to qualify under the § 613A(b)(1)(B) “fixed contract” exception to the repeal of percentage depletion. In addition, Exxon timely filed another claim for refund with the IRS on January 8, 1992, seeking a refund of 1975 tax allegedly overpaid in the sum of $40,052,850, of which $695,396 related to additional fixed-contract percentage depletion. The Commissioner allowed none of Exxon’s 1975 refund claims relating to percentage depletion and, consequently, by a petition filed with the court on October 30, 1996, Exxon instituted this suit for refund.

On July 30, 1997, the Government filed a motion for summary judgment, pursuant to RCFC 56. In its summary judgment motion, defendant maintained that with respect to post-1974 taxable years, the RMFP method prescribed in Treas.Reg. § 1.613-3(a) never applies when percentage depletion is allowable under the § 613A(b)(1)(B) fixed contract exception. Exxon, 40 Fed.Cl. at 80 . Rather, argued the Government, when Congress enacted § 613A into law, it “pegg[ed] the allowance for percentage depletion for fixed contract gas ... to the actual sales prices in effect on February 1, 1975.” Id. at 81 (quoting Def. MSJ at 23 (emphasis in original)). 12 Defendant asserted, further, that “even if the actual sales of natural gas are made after the gas has been converted into a refined product (as in this case), the prices received on those sales (as fixed by the long-term contracts in effect on February 1, 1975) determine the percentage depletion allowance.” Id. (quoting Def. MSJ at 24).

By an opinion filed on January 7, 1998, the court denied the Government’s summary judgment motion and ordered that the case proceed to trial. Exxon, 40 Fed.Cl. at 93 . All of the reasoning behind our denial of the Government’s summary judgment motion need not be reiterated herein, but a brief synopsis will lend useful context to the present discussion. 13

At the outset, the court determined that “the Code and pertinent Treasury Regulations unambiguously direct an integrated natural gas producer to Treas.Reg. § 1.613-3(a) for guidance as to the manner in which its percentage depletion allowance must be computed in post-1974 taxable years.” Exxon, 40 Fed.Cl. at 83 . Moreover, we took “it as settled that, prior to 1975, Treas.Reg. § 1.613-3(a) validly applied to every case in which an integrated natural gas producer claimed an allowance for percentage depletion, even where the resultant RMFP exceeded the actual selling price of the natural gas in question.” Id. at 86 (citing Exxon I, 88 F.3d at 975-76, 980 ). With the foregoing in mind, the court addressed defendant’s contention that whenever percentage depletion is allowable under the posH974 fixed contract exception, the RMFP method prescribed in Treas.Reg. § 1.613-3(a) is inapplicable.

Beyond our general discomfiture over the Government’s attempt to repudiate its own Treasury Regulation, Exxon, 40 Fed.Cl. at 88 , we noted that Treas.Reg. § 1.613-3(a), due to its legislative character, must be sustained unless the RMFP method prescribed thereunder “produces results which are arbitrary, capricious, or manifestly contrary to the post-1974 statutory percentage depletion scheme.” Id. at 86 (citing Chevron, 467 U.S. at 844, 104 S.Ct. 2778 ; Portland Cement, 450 U.S. at 169 , 101 S.Ct. 1037 ; Schuler, 109 F.3d at 755). We noted further that, under the foregoing test, the court could evaluate the validity of Treas.Reg. § 1.613-3(a) narrowly, as applied to the facts of this case, or broadly, by considering whether the RMFP *597 method is facially invalid whenever the post-1974 fixed contract exception applies. Exxon, 40 Fed.Cl. at 83, 86-87 .

As to the validity of Treas.Reg. § 1.613-3(a) on an as-applied basis, i.e., in specific relation to Exxon’s 1975 percentage depletion allowance, we concluded that such an analysis would necessitate a fact-intensive inquiry into whether the RMFP proposed by Exxon produces a reasonable result. Id. at 87. Even assuming that judicial inquiry into the reasonableness of an RMFP is appropriate in any case, given the Federal Circuit’s forceful holding to the contrary in Exxon I, 88 F.3d at 980 , we were constrained to hold, on the undeveloped record then before the court, that a “case-specific reasonableness analysis raises genuine issues of material fact that cannot be resolved summarily.” Exxon, 40 Fed.Cl. at 87 . Regarding the facial validity of Treas.Reg. § 1.613-3(a), we noted that there was “not even a scintilla of evidence before the court that Treas.Reg. § 1.613-3(a) systematically causes a material distortion of the ‘gross income from the property,’ ” where percentage depletion is allowable under the post-1974 fixed contract exception. Id. at 88. Further, as discussed above, “the RMFP calculation aims to ensure that an integrated producer is entitled to no greater percentage depletion deduction, for any given quantity of natural gas extracted, than its nonintegrated competitors.” Id. at 77 (citing Exxon I, 88 F.3d at 975 ). Given the foregoing, we reasoned, an inquiry into the facial validity of Treas.Reg. § 1.613-3(a) must consider whether the application of the RMFP method, in cases to which the posft-1974 fixed contract exception applies, “would upset the competitive balance that Congress sought to strike between integrated and nonintegrated producers.” Exxon, 40 Fed.Cl. at 92 . Needless to say, we concluded that “[w]hether Treas.Reg. § 1.613-3(a) systematically places nonintegrated producers at a competitive disadvantage is a question which turns upon complex factual determinations requiring a trial on the merits.” Id. at 91.

In short, having determined that an inquiry into the validity of Treas.Reg. § 1.613-3(a), either facially or as applied to the facts of this case, implicated genuine issues of material fact, the court was constrained to hold that summary judgment was inappropriate. Exxon, 40 Fed.Cl. at 87-88, 91, 93 . Trial commenced shortly thereafter, on January 26, 1998, and ended on February 13, 1998. We now turn to an overview of the evidentiary record compiled at trial.

IV. Evidence Presented At Trial

Fifteen witnesses were called to testify at trial, eight for Exxon and seven on the Government’s behalf, and all were qualified by the court as experts in various fields of knowledge relating to the natural gas industry. Fourteen of these experts also submitted written reports, all of which were received in evidence without substantive objection from either party. Moreover, several of the experts, having been employed in the Texas natural gas industry in 1975, testified as to certain factual matters purporting to be within their personal recollection. The proof fell into three broad area: (i) the computation of the RMFP; (ii) the qualification of the HL & P and SWEPCO contracts as “fixed contracts” under § 613A(b)(2)(A); and (iii) the computation of Exxon’s total “gross income from the property” (GIFP) qualifying for percentage depletion in 1975. This opinion reaches and decides the first two issues only. 14 Because *598 we take up the evidence pertinent to the HL & P/SWEPCO “fixed contract” issue separately, in the penultimate section of this opinion, the following discussion is confined to the evidence presented by the parties with respect to the RMFP issue.

At trial, Exxon presented evidence purporting to establish each of the three basic elements of the RMFP determination: (i) the relevant market area; (ii) the comparability of the gas produced in such market area to Exxon’s gas; and (iii) the qualification of selected sales of comparable gas in such market area as wellhead sales, i.e., sales of raw gas made “in the immediate vicinity of the well,” within the meaning of Treas.Reg. § 1.613-3(a). As in Exxon I, 33 Fed.Cl. at 271 , Exxon presented an RMFP study prepared by its natural gas pricing expert, Jonathan Ellis. With respect to the gas that Exxon produced from the 369 properties in issue during 1975, Mr. Ellis opined that the relevant market area in 1975 consisted of Texas Railroad Commission Districts 2, 3, 4, 5, and 6. 15 Districts 2 through 6 encompass roughly the eastern third of Texas, including the Texas Gulf Coast, the East Texas region adjoining Louisiana and Arkansas, the southern tip of Texas, and the Houston and Dallas/Fort Worth metropolitan areas.

Based upon a sample of 2,058 transactions alleged to be qualifying sales of comparable gas occurring within the Texas Gulf CoasV East Texas region in 1975, Mr. Ellis opined that for purposes of computing Exxon’s 1975 percentage depletion allowance, the RMFP is $0.7645/Mcf. 16 In addition, Mr. Ellis presented three smaller, alternative RMFP samples, subsets of the foregoing, that are summarized later in this discussion. In determining that the 2,058 transactions in his primary sample qualify for inclusion in his RMFP calculation, Mr. Ellis relied, in part, upon 1975 annual reports filed by natural gas pipeline companies with the Federal Power Commission (FPC), the predecessor agency to FERC, and the Gas Utilities Division (GUD) of the Texas Railroad Commission. Mr. Ellis also relied upon certain gas purchase contracts, i.e ., contracts by which natural gas pipeline companies bought gas from gas producers, obtained from various pipeline companies that operated in the Texas Gulf CoasV East Texas region in 1975, at least where such contract files were available. 17

As to the comparability of the gas represented in his RMFP sample to the Exxon gas in issue, Mr. Ellis relied upon a study prepared by Roland Pohler, a registered petroleum engineer and Exxon employee of 35 years, now retired. Although his report and *599 testimony focus principally upon the comparability of Exxon’s gas to other gas produced throughout the Texas Gulf Coast/East Texas region, Mr. Pohler also addressed the history and operations of EGS, as well as certain technical aspects of natural gas production, transportation, and processing. On the basis of his gas comparability study, Mr. Pohler opined that the Exxon gas production in issue was comparable or superior to the gas represented in the Ellis RMFP study.

Additional support for Mr. Pohler’s conclusion was furnished by Jeff Buie, Durland Eakin, and John Hague, each of whom was employed by a major natural gas pipeline company operating in the Texas Gulf Coast/ East Texas region in 1975—Houston Pipe Line Company (HPL), Lo-Vaca Gathering Company, and United Gas Pipe Line Company, respectively. 18 Messrs. Buie, Eakin, and Hague each opined that if the Exxon gas committed to the 18 long-term contracts in issue had been available for sale on the open market in 1975, such gas would have brought the highest price offered by pipeline companies operating in the Texas Gulf Coast/East Texas region. Mr. Buie also testified, in support of Mr. Ellis’ determination of the relevant market area, supra, that gas producers in the Texas Gulf Coast/East Texas region considered the pipeline companies in that region to be a distinct market for then-gas in 1975. Moreover, Messrs. Buie, Ea-kin, and Hague assisted Mr. Ellis by reviewing gas purchase contract files and other business records obtained from their respective former employers, ie., HPL, Lo-Vaca, and United, for the purpose of identifying transactions qualifying for inclusion in the RMFP computation.

In addition to the aforementioned experts, Exxon also called C. Ronald Platt, a registered professional engineer with over 35 years of experience relating to the evaluation, development, production, and operation of oil and gas properties. Mr. Platt submitted a study that purports to identify each of the wells that produced the gas represented in Mr. Ellis’ 2,058-transaction RMFP sample. Further, Mr. Platt’s study attempts to quantify the value that a producer adds to its natural gas, after extraction but prior to sale, by performing such functions as transportation, compression, and dehydration of the gas. 19 As discussed below, the RMFP of $0.7645/Mcf computed by Mr. Ellis reflects certain adjustments made in reliance upon Mr. Platt’s study.

Responding to Exxon’s RMFP case, the Government presented its own RMFP study, prepared by Ronald Robles, an IRS revenue agent engineer since 1982. Unlike Mr. Ellis, Mr. Robles gave no definitive opinion regarding a single RMFP that, in his view, should apply to the 1975 Exxon gas production in issue. Rather, Mr. Robles presented three different RMFP computations, of which two yield an RMFP of $0.34/Mcf, and the other yields an RMFP of $0.36/Mcf. Mr. Robles’ three RMFP computations are based upon 1,925 transactions (in one case, only 1,915 such transactions are used) that purport to be wellhead sales. In ascertaining whether those 1,925 transactions qualified as wellhead sales, Mr. Robles relied upon the same sources of information that Exxon’s experts used, i.e., 1975 FPC and GUD annual reports filed by pipeline companies, and the gas purchase contract files that Exxon had obtained from various pipeline companies.

Mr. Robles based his RMFP computations upon a relevant market area defined as the entire State of Texas. Pursuant thereto, Mr. *600 Robles relied upon the opinion of Theodore Welp, a retired IRS geologist, that the entire State of Texas constituted a single market area for natural gas in 1975. As to whether natural gas produced throughout the State of Texas in 1975, as represented in Mr. Robles’ RMFP study, was comparable to the gas produced by the 369 Exxon properties in issue, located in the Texas Gulf Coast/East Texas region, the Government presented no gas comparability study akin to the study Mr. Pohler prepared for Exxon. Rather, the Government relies upon Mr. Welp’s bare opinion that, for purposes of computing an RMFP, all gas produced in the State of Texas is comparable. 20

The remainder of the Government’s RMFP case was directed toward rebutting various aspects of the conclusions reached by Exxon’s experts. Donald Nicol and Bates Martin, both registered professional engineers, joined with Mr. Robles in attacking the standards that Mr. Ellis developed to identify 2,058 transactions that purportedly qualify for inclusion in the RMFP calculation, as well as the conclusions that Messrs. Buie, Eakin, and Ellis formed upon reviewing the various pipeline company contract files in evidence. 21 Moreover, the Government called Warren Edmonds, the deputy director of the Federal Energy Regulatory Commission’s Office of Pipeline Regulation, for the purpose of demonstrating that Mr. Ellis’ standards are inconsistent with the definition of a wellhead sale prescribed by FERC regulations. Mr. Martin also sought to debunk Mr. Pohler’s gas comparability study, assailed Mr. Platt’s well identification study, and challenged the accuracy of Mr. Platt’s estimates of the value added to natural gas when the producer transports, compresses, or dehydrates such gas prior to sale.

In short, the trial of this case presented a classic “battle of experts” with sharply opposing opinions. The intensity of this clash of warring opinions is concisely summarized by comparing the multiple RMFP computations that each litigant has presented to the court, as follows:

Description Of RMFP Number Of Volume-Weighted Total Volume Total Value Average Price

Sample Transactions Of Gas (Mcf) Of Gas ($) (proposed RMFP) 22

For Exxon:

Primary sample 2,058 764,464,493 584,416,403 $0.7645/Mcf 23

*601 Description Volume-Weighted Of RMFP Number Of Total Volume Total Value Average Price Sample Transactions Of Gas (Mef) Of Gas ($) (proposed RMFP)

Subsample # 1 288 120,293,627 98,672,715 0.8203/Mcf

Subsample # 2 56 36,697,547 28,562,035 0.7783/Mcf

“Fixed contract” subsample 460 127,136,289 77,849,167 0.6123/Mcf

“Pristine” subsample 22 8,477,122 6,897,978 0.8137/Mcf 24

For the Government:

Primary sample 1,925 1,183,770,526 408,109,009 $0.3448/Mcf

“Expanded” sample 1,925 1,238,819,423 442,575,748 0.3573/Mcf

“Fixed contract” subsample 1,915 1,178,632,915 399,689,448 0.3391/Mef.

As the foregoing tabulation illustrates in striking fashion, the disparity between the respective RMFPs calculated by Exxon and the Government, here at bar, is simply enormous. 25

Exxon’s motive in presenting five different RMFP calculations is clear. What Exxon seeks to address is the possibility that the court might reject Mr. Ellis’ 2,058-transac-tion primary RMFP sample, on the ground that some of the transactions included therein fail to qualify for consideration in the RMFP computation. Indeed, as explained, infra, we do reject Mr. Ellis’ primary RMFP sample, on precisely that ground. Having apparently foreseen this contingency, Exxon points out that it is nonetheless feasible for the court to calculate a valid RMFP on the basis of a subsample made up of the remaining qualified transactions. Thus, so as to impress upon the court the ready availability of alternative RMFP computations to choose from, Exxon has presented four subsamples made up of purported qualifying transactions. We shall address all five of Exxon’s RMFP computations, as well as the Government’s three RMFP computations, in due course, upon reaching the merits of the RMFP issue.

Exxon’s litigation strategy is, of course, firmly rooted in Exxon I. Then, as now, Mr. Ellis presented a huge sample of allegedly qualified transactions—2,228 transactions, to be exact—for the trial court’s consideration in determining the 1974 RMFP. Exxon I, 33 Fed.Cl. at 271-72 . Grave flaws were evident, however, in the criteria that Mr. Ellis used to select his 2,228 transactions. Specifically, the court found that in many of the transactions selected by Mr. Ellis, the producer had added value to the gas, prior to sale, by means of transportation, compression, or dehydration. Id. at 275 . The court noted, further, that courts historically have based the RMFP computation upon comparable “sales made at the ‘well mouth’ or at the ‘wellhead or separator,’ ” id. at 277 , 26 but *602 never upon the value added to the gas by post-production activities such as transportation, compression, or dehydration. Id. at 275-77 (citing Cannelton, 364 U.S. at 88 , 80 S.Ct. 1581 ; Panhandle, 187 Ct.Cl. at 150-51, 227, 236 , 408 F.2d at 704 ; Hugoton I, 161 Ct.Cl. at 274, 316 , 315 F.2d at 869, 892 ; Brea Cannon Oil Co. v. Commissioner, 77 F.2d 67, 69-70 (9th Cir.), cert. denied, 296 U.S. 604 , 56 S.Ct. 120 , 80 L.Ed. 428 (1935); Consumers, 78 F.2d 161 ; Greensboro, 79 F.2d 701 ; Shamrock, 35 T.C. at 989, 1030, 1037 ). Therefore, given the foregoing, the court held that transactions involving transportation, compression, or dehydration of the gas prior to sale, had to be excluded from the 1974 RMFP computation. Exxon I, 33 Fed.Cl. at 275, 277 . Moreover, due to the evident impracticability of parsing a vast sample of 2,228 transactions, in order to ascertain which transactions involved no transportation, compression, or dehydration of the gas prior to sale, the court held that Exxon had failed to carry its burden of proving an RMFP. In so holding, the court stated:

The vastness of Exxon’s sample hindered rather than helped the court determine the accuracy of the proposed RMFP. A reasonable number of sales that had been sufficiently analyzed to demonstrate that the sales constituted “a fair selection of contracts” appropriate for RMFP determinations, would have been more persuasive. Therefore, the court concludes that Exxon has not met its burden of proving by a preponderance of the evidence ... an acceptable RMFP based on the facts of this ease.

Exxon I, 33 Fed.Cl. at 278 . See also id. at 274 (“The sheer number of transactions and lack of data as to each transaction leaves the court unable to ascertain whether the sales truly are sales of raw gas in the immediate vicinity of the well”), 275 (to same effect), 277 (same).

On appeal, the Federal Circuit affirmed, as not clearly erroneous, the trial court’s holding that the RMFP computation must exclude transactions in which the value of the gas was enhanced, prior to sale, by transportation, compression, or dehydration. Exxon I, 88 F.3d at 977-78 . Having expressly affirmed the trial court’s decision on this point, the Federal Circuit went on to suggest that it would be “preferable” to cure such tainted transactions by subtracting the costs of transportation and dehydration (and, by necessary implication, compression) from the sales price of the gas. Id. at 978 (citing Panhandle, 187 Ct.Cl. at 175 , 408 F.2d at 718 ).

Here at bar, consistent with the Federal Circuit’s express holding in Exxon I, Exxon has presented two RMFP computations which purport to be based upon transactions that involved no transportation, compression, or dehydration of the gas prior to sale—Exxon’s 56-transaction subsample and Exxon’s “pristine,” 22-transaction sample, supra. Further, so as to cover all the bases, Exxon has adopted the Federal Circuit’s “preferable” method, in connection with its primary, 2,058-transaction RMFP sample, its 288-transaction subsample, and its 460-transac-tion “fixed contract” subsample, meaning that the sales price of the gas in many of the transactions included therein has been adjusted downward by the estimated costs of any transportation, compression, or dehydration related to such transactions, as determined by Mr. Platt. 27

Inasmuch as its primary RMFP computation is based upon 2,058 transactions, Exxon is plainly unmoved by the trial court’s well-considered remarks in Exxon I, relative to the burdens that a huge RMFP sample places upon the process of adjudicating RMFP cases by trial. See Exxon I, 33 Fed.Cl. at 274, 275, 277, 278 . Exxon’s indifference is, no doubt, attributable to the fact that in Exxon I, although the Federal Circuit acknowledged that the “calculation of the RMFP is a difficult and sometimes onerous task,” 88 F.3d at 976 , it nonetheless concluded that the daunting nature of that task does not excuse the trial court from attempting to identify transactions that are properly includible in the RMFP calculation, even if such qualifying transactions are effectively buried within a conglomeration of over 2,000 *603 other transactions. Moreover, the Federal Circuit held that the Court of Federal Claims had committed reversible error “by truncating its RMFP analysis thus not reaching the issue of whether Exxon’s [RMFP] study contained any valid transactions from which an RMFP could be determined.” Id. at 979 (emphasis added).

Here at bar, of course, we are bound by the Federal Circuit’s directive in Exxon I. Thus, if the record contains any competent evidence of qualifying sales of comparable gas within the relevant market area in 1975—even if the record is voluminous, burdensome to work with, and inclusive of many nonqualifying transactions—the court must determine an RMFP from whatever probative evidence is at hand. Yet, the court feels constrained to observe that we are faced with much the same dilemma as the trial court in Exxon I, and it is with no less apprehension that we approach the 2,058 transactions that Exxon has presented for consideration. 28

At trial, in support of the opinions and reports of its expert witnesses, Exxon offered a staggering volume of documentation into evidence, virtually all of which the Government acquiesced to, surprisingly, without objection, by stipulating that such documents were admissible. Said documentation amounts to roughly 300,000 pages, enough to fill 268 large document storage boxes. 29 Most of this documentary bulk is attributable to two exhibits that contain numerous pipeline company gas purchase contract files, corresponding to most of the 2,058 transactions in Exxon’s RMFP sample. Those two exhibits, PX 14a and PX 14b, fill 84 and 154 document storage boxes, respectively. Despite the firm assurances of both parties that the entire contents of PX 14a and PX 14b are material and relevant to the outcome of this case, the court soon found, upon retiring to consider and weigh the evidence adduced at trial, that such contract files contain vast quantities of irrelevant surplusage. 30

Another troubling aspect of Exxon’s 2,058-transaetion RMFP sample is that only a minuscule fraction of those 2,058 transactions were actually mentioned at trial, and in even fewer cases were the underlying pipeline company contract files meaningfully examined through the direct testimony and cross-examination of a witness. 31 Only 10 such transactions were the subject of testimony by witnesses purporting to have direct firsthand knowledge, dating to 1975, that is pro *604 bative of the qualification of such transactions for inclusion in the RMFP computation. Much of this supposed eyewitness testimony was speculative or otherwise inconclusive, however, as it was concerned with transactions that took place 23 years prior to the trial of this case. 32 Thus, virtually all of the meager testimonial record concerning the qualification of Exxon’s 2,058 transactions for inclusion in the RMFP computation is pure, unadulterated, opinion testimony.

Notwithstanding all of the foregoing circumstances, the court has dutifully labored over the documentary record in search of qualifying transactions, 33 in compliance with the Federal Circuit’s directive in Exxon I, 88 F.3d at 979 . Having justifiably ventilated our warm concerns over the state of the evidentiary record in this case, we now turn to the merits of the case at bar. First, we address the relevant market area, with respect to the 369 Exxon properties in issue. Next, the court shall examine the issue of gas comparability and, thereafter, undertake the selection of a sample of qualified transactions on which to base the RMFP computation. Lastly, we shall consider whether the HL & P and SWEPCO contracts were “fixed contracts,” within the meaning of §§ 613A(b)(l)(B) and 613A(b)(2)(A).

DISCUSSION

In every federal income tax refund .suit, the taxpayer must carry the heavy burden of overcoming the presumption that the Commissioner’s determinations are correct as a matter of law. Welch v. Helvering, 290 U.S. 111, 115 , 54 S.Ct. 8 , 78 L.Ed. 212 (1933); Transamerica Corp. v. United States, 902 F.2d 1540, 1543 (Fed.Cir.1990). As a consequence, initially, Exxon must go forward with sufficient probative evidence to support a finding contrary to the Commissioner’s determination. Danville Plywood Corp. v. United States, 899 F.2d 3, 7 (Fed.Cir.1990). In addition thereto, Exxon must carry its ultimate burden of affirmatively establishing each operative element of its 1975 refund claim by a preponderance of the evidence. Transamerica, 902 F.2d at 1543 ; Tucker v. United States, 8 Cl.Ct. 180, 186 (1985).

Further, it must be remembered that the taxpayer’s burden weighs especially heavy when the merits of its suit for refund hinge upon the claimed entitlement to an

*605 income tax deduction. This is clearly so, for it is firmly settled that income tax deductions are a matter of legislative grace and are to be narrowly construed. INDOPCO, Inc. v. Commissioner, 503 U.S. 79, 84 , 112 S.Ct. 1039 , 117 L.Ed.2d 226 (1992); Commissioner v. Sullivan, 356 U.S. 27, 28 , 78 S.Ct. 512 , 2 L.Ed.2d 559 (1958); New Colonial Ice Co. v. Helvering, 292 U.S. 435, 440 , 54 S.Ct. 788 , 78 L.Ed. 1348 (1934); Schuler, 109 F.3d at 755; Iowa Southern Util. Co. v. United States, 841 F.2d 1108, 1113 (Fed.Cir.1988). As the Supreme Court has repeatedly admonished, the foregoing maxim is particularly apposite to the allowance for percentage depletion, which “first came into the tax structure in 1926 and has been consistently regarded as a matter of legislative grace.” Paragon Jewel Coal Co. v. Commissioner, 380 U.S. 624, 631 , 85 S.Ct. 1207 , 14 L.Ed.2d 116 (1965). See also United States v. Swank, 451 U.S. 571, 577 , 579 n. 11, 101 S.Ct. 1931 , 68 L.Ed.2d 454 (1981); Parsons v. Smith, 359 U.S. 215, 219 , 79 S.Ct. 656 , 3 L.Ed.2d 747 (1959); Commissioner v. Southwest Exploration Co., 350 U.S. 308, 312 , 76 S.Ct. 395 , 100 L.Ed. 347 (1956); Anderson v. Helvering, 310 U.S. 404, 408 , 60 S.Ct. 952 , 84 L.Ed. 1277 (1940); Helvering v. Bankline Oil Co., 303 U.S. 362, 366 , 58 S.Ct. 616 , 82 L.Ed. 897 (1938). Moreover, where the taxpayer’s proof depends largely, if not almost exclusively, upon the opinions of its expert witnesses, as in the case at bar, such opinion testimony is not conclusive and binding upon a court sitting as the trier of fact. Dayton Power & Light Co. v. Public Util. Commission, 292 U.S. 290, 299 , 54 S.Ct. 647 , 78 L.Ed. 1267 (1934); Sartor v. Arkansas Natural Gas Corp., 321 U.S. 620, 627-29 , 64 S.Ct. 724 , 88 L.Ed. 967 (1944); Sternberger v. United States, 185 Ct.Cl. 528, 535-36 , 401 F.2d 1012, 1016 (1968) (per curiam) (“Even uncontradicted opinion testimony is not conclusive if it is intrinsically nonpersuasive.”); Mims v. United States, 375 F.2d 135 , 140 & n. 2 (5th Cir.1967). 34 With the aforesaid familiar principles in mind, we first consider whether Exxon has carried its burden of proving the relevant market area for purposes of computing the RMFP, relative to the taxable year 1975, with respect to the 369 Exxon properties in issue.

I. Relevant Market Area In 1975

The fundamental principles that guide our determination of the relevant market area were first laid down by the Court of Claims in the Hugoton I and Hugoton II decisions, supra, and later refined in the Panhandle case. In the latter decision, the Court of Claims stated that in determining the relevant market area in an RMFP ease, “[t]here are only two things required under the Hugoton case: ‘(1) the area should be representative of the taxpayer’s production, and (2) comparable gas should be used’.” Panhandle, 187 Ct.Cl. at 155 , 408 F.2d at 706 (citing Hugoton II, 172 Ct.Cl. at 463-65 , 349 F.2d at 430-31 ). Under the aforementioned standard, it is evident that the geographical definition of the relevant market area is closely intertwined with, and must be considered in conjunction with, the gas comparability issue. Stated differently, no geographical area can qualify as the relevant market area, for purposes of computing the RMFP, unless it is also demonstrated that the gas produced and sold within that area is “ ‘reasonably or substantially similar’ ” to the taxpayer’s gas. Hugoton I, 161 Ct.Cl. at 281 , 315 F.2d at 871 (quoting Phillips Petroleum Co. v. Bynum, 155 F.2d 196, 198 (5th Cir.), cert. denied, 329 U.S. 714 , 67 S.Ct. 44 , 91 L.Ed. 620 (1946)).

For this reason alone, we must reject the Government’s contention that the relevant market area in 1975 was the entire State of Texas. As explained above, the Government failed to present a statewide gas comparability study in support of its position. Instead, the Government’s market area expert, Mr. Welp, merely voiced a naked opinion that, for purposes of computing the RMFP, here at bar, all gas produced throughout the State of Texas in 1975 was comparable. More importantly, the Government’s total failure of proof on the issue of gas comparability, on a *606 statewide basis, completely invalidates Mr. Robles’ three RMFP computations, all of which are premised on a statewide market area.

Given the foregoing, the singularly important question to be answered is whether Exxon has established, by a preponderance of the evidence, that for purposes of computing an RMFP with respect to Exxon’s 1975 gas production from the 369 properties in issue, the relevant market area was, in fact, the Texas Gulf Coast/East Texas region, as delineated by Texas Railroad Commissions 2 through 6, inclusive. As noted above, a later section of this opinion shall address Exxon’s proof on the gas comparability issue. However, first we must consider whether the Texas Gulf Coast/East Texas region was geographically “representative of the taxpayer’s production” in issue. Panhandle, 187 Ct.Cl. at 155 , 408 F.2d at 706 . We begin with an overview of the natural gas industry in the Texas Gulf Coast/East Texas region, as it existed in 1975.

A. The Natural Gas Industry In The Texas Gulf Coast/East Texas Region In 1975

Within the Texas Gulf Coast/East Texas region, natural gas is principally found in the Houston Embayment, the Rio Grande Embayment, and the East Texas Basin. The terms “embayment” and “basin” are used in the industry to describe large geographic areas containing many natural gas “fields.” Generally, a “field” is a localized geographic area that overlays a single underground reservoir of natural gas, or multiple such reservoirs in close proximity to another. The Houston Embayment lies in the area surrounding the city of Houston, in Texas Railroad Commission District 3. Situated to the southwest of and adjacent to the Houston Embayment, the Rio Grande Embayment encompasses the southern tip of Texas, including the southern end of the Texas Gulf Coast, in Districts 2 and 4. As noted above, roughly 95% of the Exxon gas in issue came from properties located in the foregoing areas, i.e., the gas processed in Exxon’s King Ranch, Katy, Anahuae, Pledger, Clear Lake, and Lovell Lake plants. The East Texas Basin is located roughly 100-150 miles north of Houston, in District 6 and the southeastern portion of District 5, and also extends into northwestern Louisiana. About 5% of the Exxon gas in issue was East Texas gas, i.e., the gas processed in Exxon’s Hawkins and East Texas plants. See Exxon I, 33 Fed.Cl. at 259 (similar findings as to 1974). Outside of the Texas Gulf Coast and East Texas, the other major gas-producing regions in Texas are: (i) the Fort Worth Basin, to the north, west, and southwest of the city of Fort Worth; (ii) the Permian Basin in West Texas, which extends into southeastern New Mexico as well; and (iii) the Hugoton Embayment in the northern Texas Panhandle, which also extends northward throughout the Oklahoma Panhandle and southwestern Kansas. 35

In 1975, an extensive network of natural gas pipeline systems covered the Texas Gulf Coast area, connecting the gas fields located therein with gas consumers. Such gas pipelines, EGS included, ran generally in a southwest-to-northeast direction and were concentrated in a geographical corridor extending about 60 to 100 miles inland from the Gulf Coast, commonly known as “Pipeline Alley.” East Texas also contained many gas pipelines, albeit in somewhat lesser number and density than along the Gulf Coast, including the East Texas segment of EGS.

Natural gas pipeline companies in the Texas Gulf Coasi/East Texas region (and elsewhere in the United States) fell into two distinct classes in 1975—interstate pipelines and intrastate pipelines. Interstate pipelines transported gas in interstate commerce, ie., for delivery to consumers situated both within and without Texas, and such gas was, therefore, subject to regulation by the Federal Power Commission (FPC). Conversely, intrastate pipelines, including EGS, transported gas solely within the State of Texas and fell within the regulatory jurisdiction of the Gas Utilities Division (GUD) of the Texas *607 Railroad Commission. Producers and pipelines doing business in the intrastate market sought to avoid any commingling of their gas with interstate gas, because that would cause such gas to become interstate gas and, thus, subject to FPC price controls. Exxon I, 33 Fed.Cl. at 259 -60 & n. 8 (similar findings as to 1974). See also Hugoton II, 172 Ct.Cl. at 451-52 , 457 & n. 20, 458 & n. 21, 465, 349 F.2d at 421-22 , 426 & nn. 20-21, 431 (noting distinction between interstate and intrastate gas). 36

As of 1975, most of the aforementioned pipelines in the Texas Gulf Coast/East Texas region had been in place since the late 1950s or early 1960s. In the late 1960s and early 1970s, however, the burgeoning demand for natural gas along the Texas Gulf Coast, in and about Houston, spurred the construction of pipelines to transport gas from the Permian Basin, in West Texas, to the Texas Gulf Coast. 37 By 1975, about 25% to 30% of the gas produced in the Permian Basin was being transported eastward to the Texas Gulf Coast. Such Permian Basin gas constituted roughly 15% of the total gas available in the Texas Gulf Coast/East Texas region in 1975, taking into account the gas production indigenous to that region. 38

Due to the many pipeline companies operating in the Texas Gulf Coast/East Texas region in 1975, natural gas producers in that region had a ready market in which to sell their gas. Moreover, those pipeline companies could readily resell such gas, because the Texas Gulf Coast encompassed the largest gas consuming market in Texas—the Houston metropolitan area, which experienced rapid population growth in the 1970s, and the vast petrochemical industry complexes located along the Gulf Coast in the general vicinity of Houston. Due to the foregoing, Texas was not only the leading producer of natural gas in the continental United States in the 1970s, but was also the largest gas consuming state. 39

From a pricing perspective, two distinct characteristics marked the natural gas industry in the Texas Gulf Coast/East Texas region, and elsewhere in the nation, in 1975. First, as with energy prices generally in the 1970s, natural gas prices manifested a steep *608 upward trend in 1975, in a continuation of the price trend noted in Exxon I, 88 F.3d at 970 (“The market price of natural gas doubled in 1973, and doubled again in 1974.”). Cf. Commissioner v. Engle, 464 U.S. at 211 , 104 S.Ct. 597 (noting sharp upswing in energy prices during the 1970s). Second, this upward price trend was far more pronounced in the ease of intrastate gas than in the case of interstate gas, due to the existence of federal price controls on the latter. Both phenomena are thoroughly documented in the record here at bar. For example, the weighted average cost of gas purchased (WACOG) by Houston Pipe Line Company (HPL), one of the largest Texas intrastate pipeline companies, was $1.31/Mcf in 1975, whereas HPL’s 1974 WA-COG was only $0.70/Mcf. 40 Further, current intrastate market prices in 1975, as reflected in new gas purchase contracts (or in old contracts for which the price had been renegotiated upward, a practice explained more fully below), ranged as high as $1.90 to $2.10 per Mcf. 41

Conversely, due to federal price controls, the price of Texas Gulf Coast/East Texas gas sold into interstate commerce experienced a relatively modest increase in 1975, as evidenced by the fact that United Gas Pipe Line Company, a major interstate pipeline company, had a 1975 WACOG of only $0.42/Mcf, relative to such gas. 42 Given the immense disparity between the prices that the FPC allowed the interstate pipelines to pay, and the higher, unregulated prices that the intrastate pipelines could offer, the interstate pipelines were effectively frozen out of the bidding for purchases of new gas supplies. See Exxon I, 33 Fed.Cl. at 260 (“Interstate pipelines, restricted by the FPC in what they could pay for gas, were basically priced out of the market [in 1974].”). This, in turn, caused a nationwide shortage of natural gas in the early 1970s, which continued into 1975. 43 Moreover, the aforesaid shortage was exacerbated by surging demand in the intrastate gas market, driven by the booming population and industrial centers of the Texas Gulf Coast, and at the national level, due to fears of a permanent energy shortage, caused by the oil embargo imposed by the Organization of Petroleum Exporting Countries (OPEC) following the 1973 Yom Kippur War. Id at 260 (similar findings as to 1974). See also Engle, 464 U.S. at 211 , 104 S.Ct. 597 (noting relationship between the Arab oil embargo and rising energy prices).

Given conditions of restricted supply and swelling demand, intrastate pipeline companies in the Texas Gulf Coast/East Texas region competed vigorously in bidding for new supplies of gas, giving rise to a “sellers’ market” in which gas producers exercised substantial negotiating leverage with respect to potential gas buyers, i.e., pipeline companies. See Exxon I, 33 Fed.Cl. at 261 (noting that “by 1974, many [gas] producers could practically write their own deals”). The fierce competition among intrastate pipeline companies for new gas supplies fed upon itself, sending intrastate gas prices ever higher, as a result of the price redetermination clauses contained in most gas purchase contracts in effect in 1975. A typical price redetermination clause allowed the producer to reprice its gas periodically, i.e., annually, *609 semiannually, or quarterly, to the average of the two or three highest prices observed for other gas sales to pipelines within a specified geographical area, typically consisting of one or more Texas Railroad Commission Districts. 44 See Exxon 1, 33 Fed.Cl. at 261 (explicating such price redetermination clauses). Based upon his employment as a gas purchase contract administrator with LoVaca Gathering Company, a large intrastate pipeline company, during the 1970s, Mr. Ea-kin testified that such price redeterminations accelerated the general upward trend in the market price of intrastate gas, creating “a self-feeding spiral with no end.” 45 In other words, every time a new gas purchase contract was concluded, or an existing contract price was redetermined, that set an informal regional “floor” price below which no other sales of gas in the intrastate market would fall. Thereafter, upon the discovery of a new supply of gas, competing pipelines would bid to purchase such gas, with the winning bidder inevitably having to offer a price exceeding the most recently established regional floor price. Once the newly negotiated, higher price being paid for that new gas supply became generally known in the regional market, another round of price redeterminations under pre-existing contracts would be triggered, and so on. 46

In short, from the perspective of a natural gas producer, the Texas Gulf Coast/East Texas region was characterized by a strong regional demand for such gas, active competition among numerous potential buyers of such gas, i.e., the intrastate pipeline companies operating in the region, and a steep upward price trend. We turn now to consider the parties’ contentions regarding the definition of the relevant market area.

B. Contentions Of The Parties

Exxon advances three arguments in support of its basic contention—that for purposes of computing an RMFP with respect to Exxon’s 1975 gas production from the 369 properties in issue, the relevant market area was the Texas Gulf Coast/East Texas region, as delineated by Texas Railroad Commissions 2 through 6, inclusive. First, Exxon maintains that under the doctrine of collateral estoppel, the holding in Exxon I, as to the relevant market area in 1974, supra, conclusively establishes the relevant market area for 1975, unless it is shown that the pertinent facts materially changed between 1974 and 1975. According to Exxon, the Government has the burden of proving that such a material factual difference existed, under the holding in McMullan v. United States, 231 Ct.Cl. 378, 384 , 686 F.2d 915, 919 (1982).

Second, Exxon argues that binding precedent strongly discourages relitigation of the relevant market area determination in RMFP cases. Specifically, in the Panhandle case, having noted that the Government’s position would cause the relevant market area to be “subject to revision year after year,” the Court of Claims declared that “[i]t is only reasonable that the plaintiff have some assurance that it can file annual tax returns without having to periodically reliti-gate the size, shape, and depth of the area from which its gross income from the property is to be ascertained.” Panhandle, 187 Ct.Cl. at 159 , 408 F.2d at 709 . Lastly, Exxon asserts that the doctrines of collateral estop-pel and stare decisis notwithstanding, it presented evidence at trial establishing that the Texas Gulf Coast/East Texas region was the relevant market area in 1975.

*610 As noted above, the Government’s position is simply that the entire State of Texas was the relevant market area in 1975. We have already held herein that the Government’s position cannot be sustained, given its failure to present a statewide gas comparability study. Nonetheless, in the following discussion, the court shall consider whether the Government, in fact, presented any evidence tending to rebut Exxon’s case with respect to the relevant market area determination.

C. Discussion

1. Collateral Estoppel

Under the doctrine of collateral estoppel, also known as issue preclusion, “once a court has decided an issue of fact or law necessary to its judgment, that decision is conclusive in a subsequent suit based on a different cause of action involving a party to the prior litigation.” United States v. Mendoza, 464 U.S. 154, 158 , 104 S.Ct. 568 , 78 L.Ed.2d 379 (1984). See also Montana v. United States, 440 U.S. 147, 153 , 99 S.Ct. 970 , 59 L.Ed.2d 210 (1979); Commissioner v. Sunnen, 333 U.S. 591, 597-98 , 68 S.Ct. 715 , 92 L.Ed. 898 (1948); Texas Instruments Inc. v. Cypress Semiconductor Corp., 90 F.3d 1558, 1568 (Fed.Cir.1996), cert. denied, 520 U.S. 1228 , 117 S.Ct. 1818 , 137 L.Ed.2d 1027 (1997). The purpose of the doctrine of collateral estoppel is to “relieve parties of the cost and vexation of multiple lawsuits, conserve judicial resources, and, by preventing inconsistent decisions, encourage reliance on adjudication.” Allen v. McCurry, 449 U.S. 90, 94 , 101 S.Ct. 411 , 66 L.Ed.2d 308 (1980). However, justice and fairness mandate that the doctrine of collateral estoppel is not a blunt, ponderous tool given to indiscriminate application.

Difficulty sometimes arises ... in delineating the issue on which litigation is, or is not, foreclosed. The problem involves a balancing of important interests: on the one hand a desire not to deprive a litigant of an adequate day in court; on the other hand, a desire to prevent repetitious litigation of what is essentially the same dispute.

In re Freeman, 30 F.3d 1459, 1465 (Fed.Cir.1994) (citing Restatement (Second) of Judgments § 27 cmt. c (1980)). Therefore, before collateral estoppel is held to apply, the court must determine that four conditions are satisfied, as follows:

Collateral estoppel is appropriate only if: (1) the issue to be decided is identical to the one decided in the first action; (2) the issue was actually litigated in the first action; (3) resolution of the issue was essential to a final judgment in the first action; and (4) the parties had a full and fair opportunity to litigate the issue in the first action.

Arkla, Inc. v. United States, 37 F.3d 621, 624 (Fed.Cir.1994). Mindful of the foregoing, this court has given the trial and appellate opinions in Exxon I the most careful scrutiny, in order to ascertain the nature and scope of the issues that were actually litigated and decided in those proceedings. Moreover, at the request of the parties, we have also taken limited judicial notice of their respective appellate briefs, as filed with the Federal Circuit in Exxon I, solely for the purpose of addressing Exxon’s collateral es-toppel arguments.

At the outset, in determining whether collateral estoppel bars the relitigation of the relevant market area issue in the case at bar, relative to 1975, the court must consider what the precise holding was in Exxon I, with respect to the relevant market area in 1974. Inasmuch as Exxon did not appeal the trial court’s holding as to the relevant market area in 1974, we must seek the answer to the aforesaid question in the trial court’s opinion. It is true, as Exxon points out, that the trial court in Exxon I held that the relevant market area in 1974 was the “Texas Gulf Coast and East Texas.” Exxon I, 33 Fed.Cl. at 262 . Exxon contends, further, that its proposed 1975 market area, consisting of Texas Railroad Commission Districts 2 through 6, inclusive, is the same market area as that adopted in Exxon I. However, Exxon’s position is at odds with a plain reading of the trial opinion in Exxon I, wherein the court expressly found that the “Texas Gulf Coast region consists of Texas Railroad Commission Districts 2, 3, 4 and adjacent offshore areas” and that “East Texas includes Railroad Commission District 6.” Exxon I, 33 *611 Fed.Cl. at 259 . Nowhere in the court’s opinion was District 5 mentioned. The court also found that of the 482 Exxon gas properties in dispute in the 1974 litigation, 172 such properties were located in Districts 2, 3, and 4, and 310 properties were located in District 6. Id. Again, nowhere was District 5 mentioned. Thus, Exxon’s contention that its proposed 1975 market area is identical to the 1974 market area adopted in Exxon I is plainly incorrect. Given the foregoing, we must, and do, reject Exxon’s contention that, under the doctrine of collateral estoppel, Exxon I conclusively establishes that Railroad Commission Districts 2 through 6, inclusive, were the relevant market area in 1975.

Even assuming, arguendo, that the relevant market area adopted in Exxon I was the same market area that Exxon advocates, here at bar, we would still find Exxon’s collateral estoppel argument without merit, on this record. One of the indispensable elements of collateral estoppel, as to which the proponent thereof has the burden of proof, is that “the issue to be decided [in the present case] is identical to the one decided in the first action.” Arkla, 37 F.3d at 624 (emphasis added). The Supreme Court has construed the foregoing requirement rather strictly in the context of federal income tax litigation relating to separate taxable years, as follows:

[W]here two cases involve income taxes in different taxable years, collateral estoppel must be used with its limitations carefully in mind so as to avoid injustice. It must be confined to situations where the matter raised in the second suit is identical in all respects with that decided in the first proceeding and where the controlling facts and applicable legal rules remain un changed.... If the legal matters determined in the earlier case differ from those raised in the second case, collateral estoppel has no bearing on the situation.... And where the [factual] situation is vitally altered between the time of the first judgment and the second, the prior determination is not conclusive.

Commissioner v. Sunnen, 333 U.S. 591, 599-600 , 68 S.Ct. 715 , 92 L.Ed. 898 (1948) (emphasis added). However, when similar issues of fact arise in two tax refund suits involving different tax years, any “factual differences must be material, i.e., having legal significance, to prevent operation of collateral es-toppel.” Arkla, 37 F.3d at 625 (emphasis added) (citing Montana, 440 U.S. at 162 , 99 S.Ct. 970 ). See also Montana, 440 U.S. at 163 , 99 S.Ct. 970 (collateral estoppel applied where successive suits involving the same parties were “closely aligned in time and subject matter”); United States v. Stauffer Chemical Co., 464 U.S. 165, 172 , 104 S.Ct. 575 , 78 L.Ed.2d 388 (1984) (to same effect). In addition to the foregoing precedents, Exxon cites McMullan, 231 Ct.Cl. at 384 , 686 F.2d at 919 , for the proposition that it is the Government’s burden to establish that collateral estoppel is inapplicable to the case at bar, by showing the occurrence of a material factual change in the relevant market area between 1974 and 1975.

We think Exxon gives McMullan an over-broad reading. As with the case at bar and Exxon I, McMullan presented successive tax refund suits involving different taxable years. In the first case, judgment was entered in the taxpayers’ favor on their refund claims for the years 1969-1971. Wilmington Trust Co. v. United States, 221 Ct.Cl. 686 , 610 F.2d 703 (1979) (en banc). Thereafter, in the second case, relating to the 1972 tax year, the taxpayers contended that collateral estoppel precluded the relitigation of the issues of fact and law previously litigated and decided in Wilmington. McMullan, 231 Ct.Cl. at 380 , 686 F.2d at 917 . After determining that Wilmington and the case at hand presented materially identical issues, 231 Ct.Cl. at 382-83 , 686 F.2d at 918-19 , the Court of Claims concluded “that [the Government] has not made an adequate showing that the facts in the present case differ significantly from those in Wilmington.” McMullan, 231 Ct.Cl. at 384 , 686 F.2d at 919 .

Exxon cites, and we have found, no case construing McMullan to mean that the party against whom collateral estoppel is asserted has the burden, ab initio, of disproving the sameness of the factual issues presented in successive lawsuits. That is not the law, as McMullan itself makes clear. The Court of Claims expressly treated the *612 question of whether the issues of fact and law presented by the two cases were identical as the threshold question, and only upon answering that question in the affirmative did the court turn to the question of whether the Government had shown any material factual differences between the two cases. McMul-lan, 231 Ct.Cl. at 382 , 686 F.2d at 918 . 47 Thus, as the proponent of collateral estoppel, Exxon undeniably had the initial burden of making out a prima facie case that the relevant market area determination here at bar, relative to 1975, involves issues of fact that are materially identical to the factual issues decided pursuant to the relevant market area determination in Exxon I, relative to 1974. If, and only if, Exxon carried that burden at trial, would the burden of going forward with the evidence, in rebuttal of Exxon’s prima facie case, shift to the Government. We are of the opinion, however, that Exxon has failed to establish that the relevant market area determinations in Exxon I and the present case involve materially identical issues of fact.

In reaching this conclusion, we note that, although Exxon I established that the relevant market area in 1974 was the “Texas Gulf Coast and East Texas,” 33 Fed.Cl. at 262 , the court most certainly did not hold that the Texas Gulf Coast/East Texas region continued to be the relevant market area in post-1974 years. On the contrary, with respect to the periodic price redeterminations that had become common in the Texas intrastate gas market by 1974, Judge Lydon found that the trend was clearly in the direction of statewide pricing, as follows:

Gas purchase/sale contracts, in 1974, also featured most-favored-nation or price re-determination provisions whereby pipelines agreed to raise the price each month to the highest price being paid in the area. During the early 1970s, price redetermination provisions were based on the highest prices in a particular Railroad Commission District for gas sold under “similar terms and conditions.” However, by 1974, these clauses were broadened in scope to permit the redetermined price to be the average of the two or three highest prices being paid in Railroad Commission Districts 2, 3, and 4. Eventually, by 1980, some contracts stipulated that the redetermined price would be based upon the highest price being paid in the entire state of Texas.

Exxon I, 33 Fed.Cl. at 261-62 (emphasis added) (footnote omitted).

Here at bar, with respect to 1975, Mr. Buie’s report and testimony reconfirmed the existence of a trend toward statewide pricing in the Texas intrastate gas market and the eventual emergence, by 1980, of statewide pricing. 48 We think that evidence showing how gas producers and pipeline companies geographically defined the relevant marketplace, for purposes of their periodic price redeterminations, strongly influences the determination of the relevant market area for purposes of the RMFP computation. Therefore, the industry trend away from regional price redeterminations, i.e., based upon one to three Railroad Commission Districts, and toward statewide price redeterminations, constitutes powerful evidence that the Texas intrastate gas market was in a state of flux in the mid-1970s. Consistent with the foregoing, the Exxon I court also made the following finding:

By 1972, West Texas had been connected by pipeline to the Gulf Coast, and large reserves could command prices competitive with any other reserves in the state. *613 Transportation and exchange agreements between pipelines also came into more extensive use in the early 1970s, with the result that the entire state ultimately became the market area for large reserves.

Exxon I, 33 Fed.Cl. at 261 (emphasis added).

The plain import of the above-referenced findings in Exxon I is that the Texas natural gas industry was not static in the 1974-1975 time frame, as Exxon would have it, but in a state of dynamic transition and, further, that a statewide gas market emerged sometime between the end of 1974 and the year 1980. 49 Clearly the doctrine of collateral estoppel cannot be applied so as to force this court to disregard the possibility that such a statewide market had, in fact, emerged by 1975. This is so because a potential shift in the boundaries of such market area has undeniable legal significance in an RMFP case, given the pivotal importance of the relevant market area determination. Collateral estoppel is inapplicable where factual differences from one taxable year to the next are “material, i.e., having legal significance.” Arkla, 37 F.3d at 625 . Therefore, the findings in Exxon I as to the relevant market area in 1974 cannot preclude this court from making its own independent findings as to the relevant market area in 1975.

For the sake of completeness, it must be noted that we assign no probative weight to the chorus of hospitable opinion testimony from Exxon’s expert witnesses, all to the effect that market conditions affecting gas producers in the Texas Gulf Coast/East Texas region were materially unchanged between 1974 and 1975. 50 As noted above, “[e]ven uncontradicted opinion testimony is not conclusive if it is intrinsically nonpersuasive.” Ster nberger, 185 Ct.Cl. at 535-36 , 401 F.2d at 1016 . See also Dayton Power & Light, 292 U.S. at 299, 54 S.Ct. 647 ; Sartor, 321 U.S. at 627-29 , 64 S.Ct. 724 ; Mims, 375 F.2d at 140 & n. 2. None of Exxon’s experts gave any credible testimony delineating specific, concrete facts and circumstances that were relevant to their conclusion that market conditions were unchanged between 1974 and 1975. Such bland and conclusory opinion testimony “ ‘carries its own death wound.’ ” Sternberger, 185 Ct.Cl. at 536 , 401 F.2d at 1016 (quoting NLRB v. Robbins Tire & Rubber Co., 161 F.2d 798, 800 (5th Cir.1947)).

In short, as explained above, there is substantial evidence in the record from which *614 the court may reasonably infer that, from the viewpoint of gas producers in the Texas Gulf Coast/East Texas region in the 1974-1975 time frame, the marketplace was in a state of flux. If courts were to apply collateral estop-pel so as to “freeze” the taxpayer’s relevant market area in RMFP cases such as this, where the record is replete with evidence suggesting that the marketplace was evolving, that would “create vested rights in decisions that ... [later] become obsolete or erroneous with time, thereby causing inequities among taxpayers.” Sunnen, 333 U.S. at 599 , 68 S.Ct. 715 . Thus, we are constrained to hold that Exxon I’s determination of the relevant market area in 1974 has no preclu-sive effect with respect to our determination of the relevant market area in 1975.

On similar reasoning, we also find that Exxon places unjustified reliance upon Panhandle, wherein the Court of Claims observed that a taxpayer using the RMFP method should “have some assurance that it can file annual tax returns without having to periodically relitigate the size, shape, and depth of the area from which its gross income from the property is to be ascertained.” Panhandle, 187 Ct.Cl. at 159 , 408 F.2d at 709 . 51 Panhandle was concerned with RMFP determinations for the years 1952-1956, an era in which the natural gas industry was marked by low, stable market prices and long-term fixed-price contracts. See Panhandle, 187 Ct.Cl. at 132-33 , 408 F.2d at 693 ; Exxon I, 33 Fed.Cl. at 259-60, 262 . The Court of Claims, no doubt, reasoned that, in a stable market environment, to compel the taxpayer to relitigate its relevant market area annually is unsound tax policy because it is unreasonable to presume that the taxpayer’s relevant market area changes significantly from one year to the next.

Conversely, as explained above, the natural gas market was in a state of upheaval in the 1970s, including the 1974-1975 time frame. 52 We are of the opinion that such circumstances bring another legal principle to the fore—a principle first enunciated in Hugoton II and later reaffirmed in Panhandle, as follows:

As of this time there has been no attempt to define definitively the [market] area to be considered in computing a representative “market” or “field” price. We believe that such an all-inclusive rule cannot be laid down due to the fact that each case arises in its own particular context depending upon the surroundings in which the taxpayer finds himself.

Hugoton II, 172 Ct.Cl. at 464 , 349 F.2d at 431 (emphasis added), quoted with approval in Panhandle, 187 Ct.Cl. at 168 , 408 F.2d at 714 . Accordingly, by holding that Exxon cannot rely upon the 1974 market area adopted in Exxon I, but rather, must reliti-gate the relevant market area issue anew with respect to 1975, we do no injury to precedent. On the contrary, we merely acknowledge, as we must, that where there is substantial evidence that the marketplace was in a state of dynamic transition, the determination of the taxpayer’s relevant market area necessarily must proceed de novo.

To summarize all of the foregoing, contrary to Exxon’s assertion, Exxon I does not conclusively establish that the relevant market area in 1975 was the Texas Gulf Coast/ East Texas region, consisting of Texas Railroad Commission Districts 2 through 6, inclusive. We reach this conclusion for two reasons. First, and most importantly, the relevant market area that Exxon proposes in the case at bar, supra, is not identical to the relevant market area expressly adopted in Exxon I, 33 Fed.Cl. at 259, 262 , i.e., Railroad Commission Districts 2, 3, 4, and 6, but not District 5. Second, the record clearly demonstrates a plenitude of factual differences, as between 1974 and 1975, that were potentially “material, ie., having legal significance.” Arkla, 37 F.3d at 625 . Therefore, we hold *615 that the doctrine of collateral estoppel is inapplicable to the determination of the relevant market area in 1975. Having so held, the court now turns to the merits of Exxon’s case regarding the issue of the relevant market area in 1975.

2. Determination Of The Relevant Market Area In 1975

Certain fundamental principles, laid down in the Hugoton and Panhandle cases, guide our determination of whether Exxon has carried its burden of establishing the relevant market area in 1975, relative to the gas production from the 369 Exxon properties in issue. Basically, the question is whether the Texas Gulf Coast/East Texas region, consisting of Texas Railroad Commission Districts 2 through 6, inclusive, was geographically “representative of the taxpayer’s production” in issue. Panhandle, 187 Ct.Cl. at 155 , 408 F.2d at 706 . In Hugoton I, the Court of Claims explicated generally the analytical approach to be used in determining the geographical outlines of the relevant market area, as follows:

The determination of [the RMFP] requires that: “there have been recent, substantial, and comparable sales of like gas to gasoline extracting plants, carbon black plants, and the like, from wells in the area whose availability for marketing is reasonably or substantially similar to that of the gas here involved.... [T]he test is what do ... [purchasers] pay for gas similar in quantity, quality, and availability to market?”

Hugoton I, 161 Ct.Cl. at 281 , 315 F.2d at 871 (emphasis added) (quoting Phillips, 155 F.2d at 198-99 ). “Availability to market,” from the viewpoint of a natural gas producer, hinges upon the physical proximity of the producer’s gas properties “to prospective buyers’ pipelines.” Hugoton I, 161 Ct.Cl. at 320 , 315 F.2d at 895 . 53

Putting the aforementioned “availability to market” principle in sharper focus, the Hugoton I court held that, on remand, the RMFP had to be “calculated as the average price, weighted by quantity, of comparable gas sold in the locality ” in which the taxpayer produced the gas in issue. Hugoton I, 161 Ct.Cl. at 289 , 315 F.2d at 877 (emphasis added). Subsequently, in Hugoton II, the Court of Claims reiterated that because the RMFP “should be based on sales similar in ‘availability to market,’ ” the RMFP computation “call[s] for comparable sales in the [taxpayer’s] ‘locality.’ ” Hugoton II, 172 Ct.Cl. at 464 , 349 F.2d at 430 (quoting Hugoton I, supra). Further, the court pointedly declared that “common sense dictates that when there are comparative sales within the [taxpayer’s] immediate area practicalities should limit the [RMFP computation] to their use.” Hugoton II, 172 Ct.Cl. at 464 , 349 F.2d at 431 . Stated differently, the relevant market area in an RMFP case should be, as nearly as possible, geographically coterminous with the area from which the taxpayer produced the natural gas in issue.

Hugoton II provides three reasons why, in an RMFP case, a narrowly-defined market area is generally to be preferred over an expansively defined market area. First, the immediate locality of the taxpayer’s gas production is the area in which sales of comparable gas are most likely to be found, due to the similarity, if not identicalness, of the underlying gas reservoirs. Hugoton II, 172 Ct.Cl. at 464 , 349 F.2d at 431 . Second, limiting the relevant market area, where feasible, to the immediate locality is “conducive to an easier administration of’ the RMFP computation. Id. at 464-65 , 349 F.2d at 431 . Third, conforming the relevant market area, as nearly as possible, to the immediate locality “tends to equalize the taxpayer to his surroundings, i.e., the physical area in which *616 his immediate competitors find themselves.” Id. at 465 , 349 F.2d at 431 (emphasis added). This third rationale goes to the very heart of the RMFP method, for it is “in accord with the general theory of Cannelton which tells us that in each of the three basic percentage depletion Acts, Congress indicated that integrated producers should not receive preferred treatment,” relative to their “ ‘similarly situated’ ” nonintegrated competitors. Id. at 465, 349 F.2d at 431 (emphasis added) (citing Cannelton, 364 U.S. 76 , 80 S.Ct. 1581 ) (quoting Ames v. United States, 330 F.2d 770, 773 (9th Cir.1964)).

Therefore, in evaluating the propriety of a proposed relevant market area, for purposes of an integrated producer’s RMFP computation, the court must consider whether the integrated producer, had it sold its gas at the wellhead during the taxable year in question, would have faced competition from other “similarly situated” sellers of comparable natural gas within the area under consideration. See Hugoton II, 172 Ct.Cl. at 457, 460 , 349 F.2d at 426, 428 (finding that if the integrated producer taxpayer had sold its gas at the wellhead, it would have been in competition with other producers of similar gas located in the immediate area of the taxpayer’s gas production). If the foregoing question can be answered in the affirmative, with respect to the immediate locality of the taxpayer’s gas production, then the court need look no further. Id. at 464 , 349 F.2d at 431 . Conversely, if no wellhead sales of comparable gas by potential competitors can be found within the taxpayer’s immediate locality, the court may expand the geographical scope of its inquiry and consider wellhead sales of comparable gas made elsewhere, because the relevant market area “should be broad enough to include sales of gas comparable to plaintiffs production.” Panhandle, 187 Ct.Cl. at 148 , 408 F.2d at 703 . 54

Upon applying the foregoing principles to the case at bar, we conclude that Exxon has made out a prima facie case that the Texas Gulf Coast/East Texas region, consisting of Texas Railroad Commission Districts 2 through 6, inclusive, constituted a market area that was geographically “representative of [Exxon’s] production” in 1975 from the 369 properties in issue. Panhandle, 187 Ct.Cl. at 155 , 408 F.2d at 706 . Our conclusion rests upon three findings. First, it is undisputed that all of the 369 Exxon properties in issue were located within Districts 2 through 6. 55

Second, given our prior findings that numerous pipeline companies operated in the Texas Gulf Coast/East Texas region in 1975, and that such pipeline companies competed vigorously in bidding for new gas supplies in that region, gas produced throughout the Texas Gulf Coast/East Texas region plainly manifested a ready “availability to market.” Hugoton I, 161 Ct.Cl. at 281 , 315 F.2d at 871 (citation omitted); Hugoton II, 172 Ct.Cl. at 464 , 349 F.2d at 430 . Thus, as with the market area adopted in the Panhandle case, the Texas Gulf Coast/East Texas region constituted a “common competitive-purchase area ... interlaced with competing pipelines.” Panhandle, 187 Ct.Cl. at 156 , 408 F.2d at 707 . 56

*617 Third, it is clear that, if Exxon had been free to sell the gas in issue at the wellhead in 1975, it would have faced competition from other similarly-situated gas producers in the Texas Gulf Coast/East Texas region. This was indisputably so because, as shown by several maps in evidence, natural gas was being produced by many thousands of gas wells scattered throughout that region in 1975. Further, such maps demonstrate the presence of potential competitors, i.e., other gas producers, in reasonably close proximity to the 369 Exxon properties in issue. 57 Therefore, had Exxon been free to sell its gas at the wellhead in 1975, it no doubt would have faced competition from many “wells ... whose availability for marketing [was] reasonably or substantially similar to” Exxon’s gas. Hugoton I, 161 Ct.Cl. at 281 , 315 F.2d at 871 (quoting Phillips, 155 F.2d at 198 ).

On this record, we find that there was an active natural gas market in the Texas Gulf Coast/East Texas region in 1975, involving many competing gas producers and many competing gas purchasers. 58 Moreover, said market was geographically “representative of the taxpayer’s production” in issue. Panhandle, 187 Ct.Cl. at 155 , 408 F.2d at 706 . Given the foregoing, the court need not look beyond the Texas Gulf Coast/East Texas region, in order to identify sales of comparable gas qualifying for inclusion in the RMFP computation, unless the Government affirmatively goes forward with the evidence, and demonstrates the necessity of broadening the geographic scope of our inquiry. Hugoton II, 172 Ct.Cl. at 464 , 349 F.2d at 431 .

Because the Government failed to present a statewide gas comparability study, as noted above, it failed to affirmatively prove that the entire State of Texas was the relevant market area in 1975, and that the Texas Gulf Coast/East Texas region was not. Nonetheless, we must consider whether there is any probative evidence in the record tending to rebut Exxon’s showing that the relevant market area in 1975 was the Texas Gulf Coast/East Texas region. From the perspective of a gas producer in the Texas Gulf Coast/East Texas region in 1975, one circumstance might be taken to imply that a further extension of the relevant market area is warranted — specifically, the fact that the Permian Basin in West Texas furnished about 15% of the total supply of gas available in the Texas Gulf Coast/East Texas region in 1975. Seizing upon this fact at trial, defendant strove to establish the existence of active competition between Permian Basin gas producers and producers in the Texas Gulf Coast/East Texas region. Yet, the Government failed to demonstrate the influence, if any, that the influx of Permian Basin gas exerted upon the natural gas market in the Texas Gulf Coast/East Texas region, in terms of pricing, competition, or otherwise.

We find Mr. Welp’s market area study, submitted on the Government’s behalf, supra, totally unpersuasive. In forming the conclusion that the relevant market area was *618 the entire State of Texas in 1975, Mr. Welp relied primarily upon the existence of interconnected gas pipeline systems throughout the state. Because pipeline facilities were available to transport gas from any gas producing area in Texas to any other locality in Texas, Mr. Welp reasoned, there must have been a statewide market for natural gas in 1975. However, Mr. Welp’s market area study suffers numerous infirmities, all of which relate to the fact that his opinions regarding the relevant market area consist exclusively of speculation about what “could” have happened in the Texas natural gas industry in 1975, in plain contradistinction to what, in fact, did happen. 59

Putative support for Mr. Welp’s conclusion, supra, is furnished by a tabulation, contained in his report (DX 7, SubX E), that purports to show the extent to which gas pipelines could make interconnections between gas producing areas located in different Texas Railroad Commission Districts, throughout the entire State of Texas. Yet, Mr. Welp’s tabulation of inter-district pipeline interconnections fails to address the volume of gas, if any, that was actually transported through such interconnections. Consequently, even if said tabulation is assumed to be a complete and accurate compilation of the inter-district pipeline interconnections existing within the State of Texas in 1975, 60 the court is unable to evaluate whether gas flowed through such interconnections in volumes that might materially influence the determination of the relevant market area for purposes of computing the RMFP. Moreover, Mr. Welp failed to demonstrate how such gas transportation and exchange transactions relate, if at all, to the segment of the Texas natural gas industry that is pertinent to the RMFP computation-sales of gas at the wellhead. 61

*619 More importantly, Mr. Welp’s exclusive focus upon the mere existence of interconnected pipeline systems throughout the State of Texas utterly ignores the direction of the gas flow within such pipelines. This omission is reflected in his stated opinion that any gas producer located in the Texas Gulf Coast/ East Texas region in 1975, including Exxon, could market its gas to customers located in the western two-thirds of Texas. If true, Mr. Welp’s view would suggest that gas producers in the Texas Gulf Coast/East Texas region were the immediate competitors of gas producers in West Texas, i.e., the Permian Basin. However, Mr. Welp presented not one concrete example of a 1975 transaction in which gas produced in the Texas Gulf Coast/ East Texas region was transported westward for consumption in West Texas.

We doubt that evidence of any such transaction exists. In 1975, the pipelines connecting West Texas with the Texas Gulf Coast were flowing gas from west to east, not east to west. West Texas contained no major metropolitan areas or industrial centers comparable to those located along the Texas Gulf Coast in the general vicinity of Houston. Therefore, as Mr. Ellis aptly put it at trial, the pipelines connecting West Texas with the Texas Gulf Coast were “not created to take gas from the Gulf Coast out into empty West Texas.” Tr. 916. As a consequence, West Texas pipeline companies did not bid to purchase gas in the Texas Gulf Coast/East Texas region, for westward transportation to, and eventual resale in, the West Texas marketplace. Further, given the immediate proximity of a major gas consumption market in the Texas Gulf Coast/East Texas region, gas producers in that region had no rational motive to seek to market their gas in West Texas in 1975. Thus, in terms of supplying gas to the West Texas marketplace, the notion that Texas Gulf Coast/East Texas gas producers stood in the posture of immediate competitors to Permian Basin gas producers, as Mr. Welp sought to imply, is patently fallacious.

Of course, there remains the fact that a significant volume of Permian Basin gas did flow eastward in 1975, furnishing about 15% of the total supply of gas available in the Texas Gulf Coast/East Texas region. From that circumstance, one might reasonably infer that Permian Basin gas producers were competing, to some degree, with the indigenous gas producers of the Texas Gulf Coast/ East Texas marketplace. That inference, albeit plausible, does not warrant an expansion of the relevant market area, however, because nothing in the record suggests that the aforementioned influx of Permian Basin gas exerted a material influence upon the market price of natural gas in the Texas Gulf Coast/ East Texas region in 1975. Indeed, there is substantial evidence to the contrary, in the form of the price redetermination clauses that saw prevalent usage in gas purchase contracts throughout the Texas Gulf Coast/ East Texas region in 1975, supra. In his written report, Mr. Buie describes the geographical area typically addressed by such price redetermination clauses, as follows:

[W]hile price redetermination provisions in the early 1970s had referred to prices in a particular Railroad Commission District, by 1974 and 1975 these clauses were broadened to let the redetermined price be the average of the two or three highest prices being paid in several Railroad Commission Districts. Even as early as July 1974, HPL’s contract with Hughes & Hughes for [the purchase of gas] production from the McKinney lease provided for a semiannual price redetermination to the average of the two highest prices in Railroad Commission Districts 2, 3, and 4. [PX 14a at H0071793.] By 1980, some contracts required redetermination based on the highest price being paid in the entire state of Texas, though that was not the case in 1975.

PX 2 at 12 (emphasis added) (footnote omitted).

The foregoing statement is uncontroverted and, further, conforms substantially to the findings made in Exxon I as to the usage and scope of price redetermination clauses in 1974, including the fact that statewide price redeterminations did not come into use until 1980. See Exxon I, 33 Fed.Cl. at 261-62 . Moreover, upon examining a substantial number of the pipeline company contract files in the record, this court finds that Mr. *620 Buie’s statement accurately describes the typical geographic scope of such price rede-termination clauses in 1975. All of the aforesaid contract files relate to gas produced and sold in the Texas Gulf Coast/East Texas region, consisting of Railroad Commission Districts 2 through 6, inclusive. We noted no statewide price redetermination clauses in effect as of 1975, nor any price redetermination clauses that embraced Railroad Commission Districts 7C and 8, wherein the Permian Basin is situated. 62

This finding, we think, conclusively disposes of any suggestion that for purposes of computing the RMFP, with respect to Exxon’s 1975 gas production from the 369 properties in issue, the relevant market area should include the Permian Basin. It is firmly settled that in an RMFP ease, the relevant market area should be reflective of “the physical area in which [the taxpayer’s] immediate competitors find themselves.” Hugoton II, 172 Ct.Cl. at 465 , 349 F.2d at 431 (emphasis added). Plainly, inasmuch as price redeterminations in the Texas Gulf Coast/East Texas marketplace were customarily made without reference to the price of gas in the Permian Basin in 1975, gas producers in said marketplace did not perceive Permian Basin gas producers to be their immediate competitors. For this reason, it cannot be plausibly maintained, on this record, that Permian Basin gas prices were representative of the price that Exxon could have obtained in 1975, had it sold the gas in issue at the wellhead, in the Texas Gulf CoasVEast Texas marketplace. We conclude, therefore, that the inclusion of the Permian Basin in the relevant market area, here at bar, would violate “the fundamental goal of the [RMFP] calculation,” which “is to arrive at a price that is representative of the price which would be realized by noninte-grated producers” situated similarly to Exxon. Exxon I, 88 F.3d at 976 (emphasis in original). See also Hugoton II, 172 Ct.Cl. at 465 , 349 F.2d at 431 (noting focus of relevant market area determination upon “similarly situated” nonintegrated competitors).

In sum, given all of the foregoing, the court holds that Exxon has carried its burden of proving, by a preponderance of the evidence, that the Texas Gulf Coast/East Texas region, consisting of Texas Railroad Commission Districts 2 through 6, inclusive, constituted a market area that was geographically “representative of [Exxon’s] production” in 1975 from the 369 properties in issue. Panhandle, 187 Ct.Cl. at 155 , 408 F.2d at 706 . Of course, whether the Texas Gulf Coast/East Texas region was the relevant market area, for purposes of computing the RMFP, ultimately depends upon whether Exxon has established that its 1975 gas production from the 369 properties in issue was comparable to gas produced and sold generally throughout that region. Id. Accordingly, we now turn to the issue of gas comparability-

II. Comparability Of Gas

A. Background

With respect to the issue of gas comparability, Exxon’s burden is to establish that the gas represented in the 2,058 transactions in Mr. Ellis’ RMFP study (hereinafter the “Ellis gas”) was “ ‘reasonably or substantially similar,’ ” to Exxon’s 1975 gas production from the 369 properties in issue (hereinafter the “Exxon gas”). Hugoton I, 161 Ct.Cl. at 281 , 315 F.2d at 871 (quoting Phillips, 155 F.2d at 198 ). Exxon can also discharge its burden by showing that its gas was superior to the Ellis gas. 63 Panhandle, 187 Ct.Cl. at *621 156 , 408 F.2d at 707 (holding that the taxpayer had met its burden of proving comparability because its gas was, “if anything, ... more valuable than the [gas] production throughout its selected [market] area” (emphasis added)); Exxon I, 38 Fed.Cl. at 270 (“The evidence supports a finding that the gas in issue here was comparable or superior to the gas sold in the market area applicable in this case.” (emphasis added)).

Six factors are given weight in making the gas comparability determination: (i) the volume of gas available for sale; (ii) the delivery or rock pressure of the gas; (iii) the deliverability of the producer’s wells; (iv) the location and proximity of the producer’s lease(s) to gas pipelines; (v) the hydrogen sulfide content of the gas; and (vi) the Btu content, or heating value, of the gas. Hugoton I, 161 Ct.Cl. at 320 , 315 F.2d at 894-95 ; Hugoton II, 172 Ct.Cl. at 449-50 , 349 F.2d at 420-21 ; Panhandle, 187 Ct.Cl. at 156, 219 , 408 F.2d at 707 ; Exxon I, 33 Fed.Cl. at 270 . Of the six factors listed above, the first four relate to the quantity, location, and availability of the gas, whereas the latter two relate to the chemical composition of the gas. The relevance of such gas comparability factors, in connection with the RMFP computation, lies in the degree to which they influence the price of the natural gas under consideration. Hugoton I, 161 Ct.Cl. at 281 , 315 F.2d at 872 .

B. Contentions Of The Parties

Exxon primarily relies upon the trial court’s holding in Exxon I that, with respect to the year 1974, “the [Exxon] gas in issue here was comparable or superior to the gas sold in the market area applicable in this case.” Exxon I, 33 Fed.Cl. at 270 . Given the foregoing, Exxon maintains that the doctrine of collateral estoppel bars the relit-igation of the gas comparability issue, here at bar, relative to the year 1975, because there were no material factual differences, as between the years 1974 and 1975, that might alter the gas comparability determination. In this regard, Fred Watson, a natural gas accountant employed by Exxon since 1973, testified that “[b]y far, the majority of the gas that was produced in 1975 was produced from the same properties that were at issue in 1974.” Tr. 1380. Regarding the fact that 482 Exxon gas properties were in issue in Exxon I, 33 Fed.Cl. at 259 , but only 369 Exxon properties are in issue here, relative to 1975, Mr. Watson explained that most of that difference relates to Exxon’s “unitization” of over 150 properties in the Hawkins Field in East Texas, effective January 1, 1975, meaning that the 150 unitized properties were thereafter accounted for as a single combined property. 64 As to the occurrence of any other changes in the identity of the Exxon gas properties in dispute, as between 1974 and 1975, Mr. Watson testified that although there were “other miscellaneous adds and deletes, ... the big properties such as the King Ranch leases, Katy and Pledger all were still the same between the two years.” Tr. 1381. Exxon contends, further, that the Ellis gas, here at bar, manifested no significant physical differences from the gas represented in the 2,228 transactions in the 1974 RMFP study that Mr. Ellis submitted in Exxon I. In addition, Mr. Pohler testified that his 1975 gas comparability study (PX 1), supra, utilizes the same methodology as the 1974 gas comparability study that he submitted in Exxon I.

Moreover, irrespective of its collateral es-toppel argument, Exxon also maintains that it met its burden of proving that its 1975 gas production in issue was comparable or superior to the Ellis gas. Specifically, upon considering all six of the relevant gas comparability factors, supra, pursuant to his gas comparability study, Mr. Pohler opined that Exxon’s gas was “of higher quality, on average,” than the Ellis gas. PX 1 at 44. Con *622 sistent therewith, based upon his personal experience as a gas buyer for Houston Pipe Line Company in the mid-1970s, Mr. Buie opined that if the Exxon gas in issue had been available for sale at the wellheads in 1975, “it would have set a new threshold price to be paid for natural gas.” Similarly, Mr. Eakin opined that Exxon’s gas could have commanded a wellhead price higher than any wellhead price being paid in the Texas Gulf Coast/East Texas region in 1975. In addition, Mr. Hague opined that if Exxon had made wellhead sales of the gas in issue into the interstate market, such gas would have brought the very maximum price allowable under the FPC’s price control regulations.

In response to the foregoing, the Government advances two basic arguments. First, the Government contends that Mr. Pohler’s gas comparability study is fatally flawed, in that it addresses only the “gas well gas” in issue, but not the “casinghead gas” in issue. “Gas well gas” is gas that is found in a gaseous state at reservoir conditions, ie., while in its natural state underground. Gas produced from oil wells as a byproduct of crude oil production is referred to as “casing-head gas,” because it is dissolved in crude oil at reservoir conditions, but becomes gaseous at the lesser atmospheric pressure encountered at the top, or “casinghead,” of an oil well. Gas well gas differs from casinghead gas in several respects. Oil wells that produce casinghead gas generally produce such gas in smaller volumes, at lower pressure, and at lower rates of delivery, than gas wells. Further, casinghead gas typically contains higher concentrations of the heavier liquefiable hydrocarbons (i.e., ethane, propane, butane, etc.) than gas well gas. See Exxon I, 33 Fed.Cl. at 256 (findings to same effect, relative to 1974). As discussed in greater detail below, although Mr. Pohler’s gas comparability study addresses the Btu content of the casinghead gas in issue, he admitted that his study fails to address the other five gas comparability factors, swpra, insofar as they relate to such casinghead gas. 65

Secondarily, on the Government’s behalf, Mr. Martin submitted a report that purports to demonstrate that Mr. Pohler’s methodology for comparing the Btu content of Exxon’s gas and the Ellis gas is seriously defective. However, Mr. Martin’s report and testimony focused solely upon Btu content, leaving Mr. Pohler’s determinations as to the other five gas comparability factors, supra, essentially uncontroverted. 66 Having thus delineated the litigants’ respective positions on the gas comparability issue, the discussion now turns to Exxon’s collateral estoppel argument.

C. Discussion

1. Collateral Estoppel

As the proponent of collateral estoppel, Exxon has the initial burden of making out a prima facie case that the gas comparability determination in the case at bar, relative to 1975, involves issues of fact and law that are identical to the issues that were actually litigated and decided, pursuant to the gas comparability determination in Exxon I, relative to 1974. Arkla, 37 F.3d at 624 . See also McMullan, 231 Ct.Cl. at 382-84 , 686 F.2d at 918-19 (determination that issues presented are the same is prerequisite to imposing burden of showing material factual differences upon party against whom collateral estoppel asserted). In deciding whether Exxon has met its burden, our inquiry necessarily begins with the trial court’s opinion in Exxon I. 67 That opinion furnishes little en *623 lightenment, however, for it simply enumerates the six gas comparability elements enunciated in the Hugoton and Panhandle eases, and then concludes, without any elaboration, that “[t]he evidence supports a finding that the [Exxon] gas in issue was comparable or superior to the gas sold in the market area applicable in” the taxable year 1974. Exxon I, 33 Fed.Cl. at 270 (citing Hugoton I, 161 Ct.Cl. at 320 , 315 F.2d at 894-95 ; Hugoton II, 172 Ct.Cl. at 449-50 , 349 F.2d at 420-21 ; Panhandle, 187 Ct.Cl. at 156, 219 , 408 F.2d at 707 ). Thus, it can definitely be said that a factual finding of comparability was made in Exxon I, but from that terse finding, little can be inferred about whether the factual issues presented in the case at bar are identical to the factual issues actually litigated and decided in Exxon I.

Yet, in light of the record accumulated at trial, we are convinced that the gas comparability issues presently before this court are not the same as the gas comparability issues litigated and decided in Exxon I. First, we are plainly confronted with a number of gas properties that were not at issue in Exxon I. In explaining why the number of Exxon gas properties in issue fell from 482 in 1974, to 369 in 1975, Mr. Watson cited the Exxon’s unitization of over 150 properties in the Hawkins Field in East Texas, effective January 1, 1975. Simple arithmetic instructs that if over 150 properties are aggregated into a single, unitized property, there will be at least 149 fewer properties after the unitization. Therefore, upon subtracting 149 properties from the 482 properties at issue in Exxon I, we find that as of January 1, 1975, immediately following the unitization, there existed not more than 333 Exxon gas properties that had any connection with Exxon I. Inasmuch as 369 Exxon properties are in issue with respect to the year 1975, it logically follows that at least 36 of those properties were not at issue in Exxon I. 68

What is more, in 1974, the Exxon gas in issue was produced by approximately 5,000 wells, of which about 1,000 were gas wells producing gas well gas and roughly 4,000 were oil wells producing casinghead gas. Exxon I, 33 Fed.Cl. at 259 . With respect to 1975, and in contrast to the foregoing, the Exxon gas in issue was produced by roughly 1,140 gas wells and 4,000 oil wells. 69 Although the approximate number of oil wells is seemingly unchanged, the court can scarcely overlook the fact that, between 1974 and 1975, the number of Exxon gas wells in issue increased by the net figure of 140 gas wells. We decline to merely assume that Exxon I’s comparability finding extended to 140 Exxon gas wells that either did not exist in 1974, having not yet begun production, or were otherwise not at issue in Exxon I.

Moreover, we are constrained to note that Exxon has presented absolutely no credible evidence in support of its sweeping claim that the gas represented in the 2,058 transactions in Mr. Ellis’ RMFP study, here at bar, is substantially the same as the gas that was represented in the 2,228 transactions in Mr. Ellis’ 1974 RMFP study, submitted in Exxon I. Indeed, the very fact that Mr. Ellis’ 1975 RMFP study contains 170 fewer transactions than his 1974 RMFP study implies quite the contrary. It was certainly within Exxon’s ability to present evidence that would show whether the transactions in Mr. Ellis’ 1974 and 1975 RMFP studies involved substantially similar gas. For example, at a minimum, Exxon could have presented the 1974 gas comparability study that Mr. Pohler submitted in Exxon I. In addition, Mr. Ellis no doubt could have prepared and submitted workpapers showing the extent to which the 2,058 transactions in his 1975 RMFP study correspond, in terms of the identity of the underlying gas properties, to the 2,228 transactions in his 1974 RMFP study. From Exxon’s failure to present such evidence, the court infers that such *624 evidence, if produced, would have been adverse to Exxon’s position. 70

Nor has Exxon alleged, much less shown, that the respective wells associated with Mr. Ellis’ 1974 and 1975 RMFP studies were substantially identical. Although Mr. Platt submitted a study (PX 5) that identifies the wells associated with Mr. Ellis’ 1975 RMFP study, the record contains no corresponding well identification study for the year 1974. Further, according to Mr. Platt’s well identification study, the 2,058 transactions in Mr. Ellis’ 1975 RMFP study involved hundreds of wells that first began production in 1975. 71 It cannot be rationally maintained that the comparability of the gas produced by such post-1974 wells, to Exxon’s gas, was an issue that was actually litigated and decided in Exxon I, wherein the comparability finding was concerned exclusively with wells that were producing gas as of 1974. Similarly, lacking a 1974 well identification study, the court cannot rule out the possibility that some of the wells represented in Mr. Ellis’ 1974 RMFP sample might have depleted and ceased production by 1975.

Given all of the foregoing factual differences, as between 1974 and 1975, we are unable to conclude that the gas comparability issue before this court is the same gas comparability issue that was litigated and decided in Exxon I. Such factual differences are not immaterial but, rather, relate to the issue of gas comparability, an indispensable element of the taxpayer’s burden of proof in an RMFP case. See, e.g., Panhandle, 187 Ct.Cl. at 155 , 408 F.2d at 706 (stating requirement that “comparable gas should be used”). Thus, the factual differences pertinent to the gas comparability issue, as between Exxon I and the case at bar, are indisputably “material, i.e., having legal significance.” Arkla, 37 F.3d at 625 . Consequently, we are constrained to hold that the doctrine of collateral estoppel does not preclude this court from making its own independent findings, here at bar, as to whether the 1975 Exxon gas production in issue was comparable to the gas represented in Mr. Ellis’ RMFP study. Accordingly, we now turn to the merits of the gas comparability issue.

2. Gas Comparability Determination

At trial, it was Exxon’s burden to demonstrate, by a preponderance of the evidence, that its 1975 gas production from the 369 properties in issue was “reasonably or substantially similar” to the Ellis gas, i.e., the gas represented in the 2,058 transactions in Mr. Ellis’ RMFP study. Hugoton I, 161 Ct.Cl. at 281 , 315 F.2d at 871 (internal quotation omitted). Here at the outset, we note two flaws in the gas comparability study that Mr. Pohler submitted on Exxon’s behalf. First, in order to identify the wells that produced the Ellis gas during 1975, Mr. Pohler relied upon Mr. Platt’s well identification study, which identifies 6,259 oil and gas wells that were associated with 1,810 of the transactions in Mr. Ellis’ RMFP study. Although the court is satisfied with the accuracy of Mr. Platt’s well identifications, in connection with those 1,810 transactions, 72 we are constrained *625 to note that he failed to identify any wells that were associated with the other 248 transactions in Mr. Ellis’ RMFP study. Without such well data, it is plainly impossible to ascertain whether the gas represented in those 248 transactions was comparable to Exxon’s gas. Accordingly, the 248 transactions lacking well data must be excluded from consideration in the RMFP computation, and the remainder of the discussion below is addressed exclusively to the 1,810 transactions for which well data was available.

Second, we agree with the Government that Exxon failed to meet its burden of proving comparability with respect to any of the casinghead gas in issue. As noted above, Mr. Pohler admitted that his gas comparability study completely fails to address five of the six gas comparability factors, supra (Btu content being the exception), in connection with any of the casinghead gas in issue, whether produced by the 4,000 Exxon oil wells in issue, or by the oil wells associated with the 2,058 transactions in Mr. Ellis’ RMFP study. By way of attempted justification for his failure to perform a complete comparability analysis in connection with the casinghead gas in issue, Mr. Pohler asserted that the availability of production data for oil wells that produce such gas is limited by the fact that oil wells are generally grouped together and reported by lease, not individually. Due to the foregoing, Mr. Pohler explained, “a direct comparison would have been very difficult.” Tr. 169. Admitted difficulty, however, is an insufficient response for failure of proof, where such proof is not clearly shown to be unavailable. We are not convinced, therefore, that the purported unavailability of such production data was an insurmountable obstacle. On the contrary, it is evident that Mr. Pohler did, in fact, have access to additional information that would have allowed him to address, in somewhat greater detail, the comparability of the cas-inghead gas in dispute. 73

To all appearances, Mr. Pohler’s failure to perform a comprehensive comparability analysis, relative to the casinghead gas in issue, was the consequence of a tactical decision on Exxon’s part to focus its litigation resources on gas well gas. Mr. Pohler repeatedly stressed the fact that over 90% of the Exxon gas in issue was gas well gas, and admitted, further: “So we concentrated our effort on the gas wells which produced the vast majority of the gas.” Tr. 87. In terms of costs and potential benefits, Exxon’s nearly singular focus on gas well gas, the bulk of the gas in issue, is understandable. However, that does not excuse Exxon’s failure to even attempt to make a plausible showing of comparability with respect to the casing head gas in issue. Having made the decision to ad *626 dress the comparability of its casinghead gas in cursory fashion, Exxon must bear the consequences of that decision.

Nor are we persuaded that Mr. Pohler’s comparability determinations with respect to gas well gas, infra, can be validly extrapolated to the casinghead gas in issue. 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. 74 See Exxon I, 33 Fed.Cl. at 256 (findings to same effect, relative to 1974). If Mr. Pohler’s comparability determinations for the gas well gas in issue were extrapolated to Exxon’s casinghead gas, that would, in essence, merely aggregate Exxon’s casinghead gas with its dissimilar gas well gas. To the untutored eye, this approach might obscure Exxon’s failure of proof regarding the comparability of its casinghead gas. In fact, burying Exxon’s casinghead gas within a much larger volume of dissimilar gas well gas accomplishes absolutely nothing in the way of proving that Exxon’s casinghead gas was comparable to the gas represented in Mr. Ellis’ RMFP study. Thus, on this record, the court finds that Exxon has failed to establish that its 1975 casinghead gas production from the roughly 4,000 Exxon oil wells in issue was comparable to any of the Ellis gas. Accordingly, given that finding, we hold that Exxon must exclude such casinghead gas, representing approximately 9.74% of the Exxon gas in issue, in terms of volume (Mcf), 75 from the computation of its 1975 percentage depletion allowance.

Notwithstanding the foregoing, the court finds that Exxon has met its burden of proving that its 1975 gas well gas production in issue was comparable or superior to the Ellis gas well gas. We reach this conclusion, in large part, because Mr. Pohler’s determinations as to five of the six gas comparability factors, supra, are essentially uncontrovert-ed, with Btu content being the only factor truly in dispute. In light of the evidence accumulated at trial, we address each of the six gas comparability factors below, seriatim.

a. Volume Available for Sale

The volume of gas available for sale relates to the total size of the proven, prospectively recoverable, reserves contained within a particular underground reservoir of natural gas. “Generally, the greater the volume or reserves, the greater the price the seller [can] command.” Hugoton I, 161 Ct.Cl. at 320 , 315 F.2d at 894 ; Hugoton II, 172 Ct.Cl. at 449 -50 n. 7, 349 F.2d at 420 n. 7; Panhandle, 187 Ct.Cl. at 219 , 408 F.2d 690 . See also Exxon I, 33 Fed.Cl. at 261 (finding to similar effect). A larger reserve commands a higher price, because pipeline companies are more willing to make the investment in constructing a pipeline and appurtenant facilities in order to take delivery of the gas. Stated differently, a larger supply of gas allows the pipeline company to spread, or amortize, the cost of the requisite pipeline facilities over more units of purchased gas, thereby lowering the per-unit cost of the gas.

In order to compare the total volume of gas available for sale in 1975, with respect to the 369 Exxon gas properties in issue and the gas properties relating to the 2,058 transactions in Mr. Ellis’ RMFP study (the Ellis properties), Mr. Pohler had to estimate the total gas reserves underlying such gas properties as of 1975. Using production data obtained from a commercial database of oil and gas well statistics maintained by the firm of Petroleum Information/Dwights LLC (hereinafter, the “Dwights database”), Mr. Pohler calculated the total volume of gas produced by the gas wells in issue during the 23-year period from 1975 through 1997. 76 From the cumulative production volume during the 1975-1997 period, Mr. Poh-ler deduced the total volume of gas reserves beneath each gas well in issue, as of the be *627 ginning of 1975. Having so ascertained the estimated reserves underlying the Exxon gas wells and the Ellis gas wells as of 1975, Mr. Pohler then aggregated the estimated reserves by reference to the fields in which those wells were located, in order to obtain an indication of the total volume of gas available for sale at each such field. Upon comparing the total estimated reserves underlying the largest 20 Exxon fields and the largest 20 Ellis fields, Mr. Pohler concluded that in 1975, the reserves underlying the Exxon fields were, on the average, considerably larger than the reserves underlying the Ellis fields. On this record, given defendant’s lack of opposition to Mr. Pohler’s determinations, we find that Exxon’s gas well gas was superior to the Ellis gas well gas, in terms of the respective volumes of gas that were available for sale in 1975.

b. Delivery or Rock Pressure

Natural gas, when confined in an underground reservoir in its original state, exists under conditions of pressure. Generally, such pressure is a function of the depth of the reservoir, with greater pressure encountered at greater depths. This natural pressure causes gas to flow upward through the well bore to the surface of the earth because, under the laws of nature, gas flows from a high pressure area into a lower pressure area. Panhandle, 187 Ct.Cl. at 224-25 , 408 F.2d 690 . In order for natural gas to flow freely from the producer’s well into the buyer’s pipeline, without mechanical assistance, the well must produce gas at a pressure that exceeds the operating pressure of the pipeline. Conversely, when the pipeline pressure exceeds the natural pressure at which the well can produce gas, the natural pressure of the gas must be increased, by means of mechanical compression, in order to transport the gas into the purchaser’s pipeline. See Exxon I, 33 Fed.Cl. at 256 (“A well’s pressure is an indicator of its ability to flow gas to a pipeline.”).

Although alternate measures of pressure exist, the “flowing tubing pressure” (FTP) is the most representative measure of a well’s ability to deliver natural gas into a buyer’s pipeline, inasmuch as it is measured at the wellhead, while the well is actually producing gas, and incorporates pressure losses due to friction in the well bore and reservoir. 77 “Generally, the higher the pressure [of the well], the less compression for transportation is required.” Hugoton I, 161 Ct.Cl. at 320 , 315 F.2d at 895 ; Hugoton II, 172 Ct.Cl. at 449 -50 n. 7, 349 F.2d at 420 -21 n. 7; Panhandle, 187 Ct.Cl. at 219 , 408 F.2d 690 ; see also id. at 222-23 , 408 F.2d 690 . Thus, inasmuch as it is costly to install, operate, and maintain compression facilities, gas produced by a high-pressure well is generally more valuable than gas produced by a low-pressure well.

For purposes of comparing the delivery pressures of the Exxon gas wells in issue, with the gas wells associated with the 2,058 transactions in Mr. Ellis’ RMFP study, Mr. Pohler obtained FTP measurements for such wells from the Dwights database. Upon calculating the volume-weighted average FTP. of each group of gas wells in issue, Mr. Pohler determined that Exxon’s gas wells had an average FTP of 970 psig, whereas the Ellis gas wells had an average FTP of 750 psig. 78 At trial, the foregoing determinations *628 were unchallenged by the Government and its experts. Therefore, on this record, the court finds that the Exxon gas well gas in issue was superior to the gas well gas represented in Mr. Ellis’s RMFP study, because Exxon’s gas wells had, on the average, a higher delivery pressure in 1975 than the Ellis gas wells.

c. Deliverability of Producer’s Wells

Deliverability is another measure of a well’s ability to flow gas, and is typically stated as an average daily rate of production, ie., the average volume of gas produced within a 24-hour period (Mcf/day, MMcf/day, etc.). 79 Generally, “the larger the volume [of gas] that [can] be delivered from a reserve, the greater the price the seller [can] command.” Hugoton I, 161 Ct.Cl. at 320 , 315 F.2d at 895 ; Hugoton II, 172 Ct.Cl. at 449 -50 n. 7, 349 F.2d at 420 -21 n. 7; Panhandle, 187 Ct.Cl. at 219 , 408 F.2d 690 . See also Exxon I, 33 Fed.Cl. at 261 (finding to same effect, relative to 1974). 80 Based upon the 1975 annual production volumes of the gas wells in issue, obtained from the Dwights database, Mr. Pohler determined that the daily average volume produced by Exxon’s gas wells was approximately 2.33 MMcf per day in 1975, whereas the Ellis gas wells averaged only about 0.47 MMcf per day. On the basis of the aforesaid uncontested evidence, the court finds that Exxon’s gas well gas was substantially superior, in terms of its 1975 rate of deliverability, to the Ellis gas well gas in issue.

d. Location and Proximity of Producer’s Lease(s) to Gas Pipelines

Due to the cost of laying pipelines to transport gas from the producer’s well to the purchaser’s pipeline, a relevant consideration in the valuation of natural gas is the “location of the [producer’s] leases or acreage involved, whether in a solid block or scattered, and their proximity to prospective buyers’ pipelines.” Hugoton I, 161 Ct.Cl. at 320-21 , 315 F.2d at 894 ; Hugoton II, 172 Ct.Cl. at 449 -50 n. 7, 349 F.2d at 420 -21 n. 7. A meaningful comprehension of the foregoing requires an understanding of certain pipeline industry nomenclature. In the context of sales of gas by producers to pipeline companies, the “point of delivery,” or delivery point, is the location constituting the physical point of sale, at which title to the gas passes from seller to buyer. At the point of delivery, a “custody meter” measures the volume of gas sold and delivered to the pipeline company. All pipeline company gas purchase contracts designate, in varying degrees of specificity, the point or points of delivery.

Pipelines of various sizes and capacities are used to transport gas from the well to the point of delivery and, thence, to end users. At trial, it soon became clear that different persons in the natural gas industry may use different terms to describe the same type of pipeline, or use the same term to refer to different types of pipeline. However, certain predominant usages and definitions emerged from the testimony of the parties’ expert witnesses, and are adopted herein by the court, as follows. A “flow line” is a small-diameter pipeline, typically not more than two to three inches in diameter, that transports the full wellstream from the well to a nearby field separator, where liquid water and liquid hydrocarbons (condensates) are removed from the raw natural gas. 81 See Exxon I, 33 Fed.Cl. at 257 (similar definition of flow line).

A “gathering line” is a small-diameter pipeline that transports gas away from the separator to a central delivery point in the *629 field, or to centrally-located facilities such as a dehydrator, compressor, or gas processing plant. 82 A “gathering system” is a network of gathering lines that transport gas away from multiple wells, or the appurtenant separators, to such central delivery points or facilities. 83 The foregoing definitions are supported by the preponderance of the relevant testimony at trial. 84 In addition, the pipeline company contract files in the record (PX 14a and PX 14b) routinely use the term “gathering” to refer to an arrangement whereby gas is transported from multiple wells to a central point. 85 Moreover, our conclusion as to the meaning of “gathering” is consistent with findings made in other RMFP cases. See Hugoton I, 161 Ct.Cl. at 297 , 315 F.2d at 881 (describing producer’s “gathering system” of pipelines that “gathered” gas from multiple wells to a central point for dehydration prior to delivery of the gas to the buyer); Panhandle, 187 Ct.Cl. at 162 , 408 F.2d at 710-11 (noting that producer was “gathering” the gas from 13 wells to a common delivery point), 187 Ct.Cl. at 167 , 408 F.2d at 713 (reference to such “gathering lines”), 187 Ct.Cl. at 173-74 , 408 F.2d at 717-18 (twice referring to producer “gathering” gas from its multiple wells before sale); Exxon I, 33 Fed.Cl. at 257 (gathering to processing plant); Shamrock, 35 T.C. at 989 (same).

Small-diameter gathering lines of the sort described above typically converge into medium-diameter gathering lines, sometimes termed “laterals,” which branch off from “transmission lines.” Transmission lines are large-diameter pipelines, normally ranging between 12 and 36 inches in diameter, that transport large volumes of gas from gas producing areas, i.e., gas fields, basins, or em-bayments, to areas populated by residential and industrial gas consumers. 86 See Exxon I, 33 Fed.Cl. at 258 (transmission line similarly defined); Shamrock, 35 T.C. at 989 (same). Such transmission lines are often hundreds of miles in length. 87

On this record, to summarize the foregoing, the court concludes that any pipeline which transports gas from a wellhead to a field separator is a flow line. Any pipeline, including one of a series of successive pipelines, that transports gas from the outlet of a separator to a transmission line is a gathering line. 88 A gathering line, or a gathering system, may be constructed by the producer of the gas, by the pipeline company that purchases the gas, or by each in part. When a gas purchase contract is negotiated, it is the contractual specification of the delivery *630 point which allocates the obligation to construct any necessary gathering lines between the producer and the pipeline company. In other words, upon negotiating a gas purchase contract, the producer and the pipeline company know where the producer’s gas properties are, and where the pipeline company’s nearest transmission line is. If it is agreed that the delivery point shall be at each of the producer’s wellheads, then the pipeline company must build the gathering system in order to bring the gas to its transmission line. Conversely, if it is agreed that the delivery point shall be at the pipeline company’s transmission line, then the producer must build the gathering system in order to deliver the gas. 89 Ofttimes the delivery point is located somewhere in between, as when a producer with multiple wells is contractually obligated to compress or dehydrate its gas prior to delivery. Such compression or dehydration is frequently done at central points in the field, rather than at each well, so that the producer can combine the gas streams from multiple wells, in order to achieve the cost savings that result from economies of scale. 90 Thus, the point of delivery may be situated anywhere between the outlet of the producer’s separator and a point on the pipeline company’s nearest transmission line, with the producer doing the gathering required, if any, to move the gas from its wells to the delivery point, and the pipeline company doing the gathering required, if any, to move the gas from the delivery point to its transmission line. As shall be seen, in a subsequent section of this opinion, delivery points were the subject of protracted controversy at trial, relative to the qualification of Exxon’s 2,058 transactions for inclusion in the RMFP computation.

Irrespective of whether the delivery point is located at the wellhead, at the buyer’s nearest transmission line, or somewhere in between, it is incontestable that the process of gathering gas entails the costs of installing, operating, and maintaining a gathering system. Such costs are lessened if the producer’s gas properties are “well-blocked and compactly situated,” rather than widely scattered, such that the delivery points are “better than average from the standpoint of costs of connection.” Hugoton I, 161 Ct.Cl. at 320-21 , 315 F.2d at 895 ; Hugoton II, 172 Ct.Cl. at 450 , 349 F.2d at 421 . Stated differently, gas is generally more valuable if the producer’s “acreage [is] in convenient blocks from the standpoint of gathering costs and delivery” to the purchaser. Panhandle, 187 Ct.Cl. at 156, 223 , 408 F.2d at 707 . Similarly, gas is generally more valuable if the producer’s acreage lies in close “proximity to prospective buyers’ pipelines.” Hugoton I, 161 Ct.Cl. at 320-21 , 315 F.2d at 894 ; Hugoton II, 172 Ct.Cl. at 449 -50 n. 7, 349 F.2d at 420 -21 n. 7. Given the natural gas shortage in 1975, the proximity of prospective buyers’ pipelines was a particularly strong determinant of value, because the presence of two or more pipelines operating in the general vicinity of a newly-developed gas property would set off an energetic bidding war over the producer’s gas. 91

In order to compare Exxon’s 369 gas properties with the Ellis gas properties, from the standpoint of their respective locations and proximity to prospective gas buyers’ pipelines in 1975, Mr. Pohler had the firm of Petroleum Information/Dwights LLC (ie., the proprietor of the Dwights database, supra ) plot all of the gas wells in issue upon a map of the Texas Gulf Coast/East Texas region. Based upon his visual examination of that map, Mr. Pohler opined that Exxon’s gas properties were as favorably located, with respect to the pipeline systems operating in the Texas Gulf Coast/East Texas region, as the Ellis gas properties. 92 However, in response to the court’s inquiry, Mr. Pohler was unable to articulate the standard of distance on which he based that opinion, and ultimately admitted that his opinion rested *631 upon no specific measurement standard. 93 Thus, Mr. Pohler’s pipeline-proximity study amounted to an exercise in self-serving, subjective “eyeballing.” “Eyeballing may have the advantage of ease, but it surely lacks scientific reliability in the sense of producing consistent results.” Ayers v. Robinson, 887 F.Supp. 1049, 1060 (N.D.Ill.1995) (rejecting “eyeballing” analysis of expert witness). See also Kurncz v. Honda North America, Inc., 166 F.R.D. 386, 389 (W.D.Mich.1996); Pomella v. Regency Coach Lines, Ltd., 899 F.Supp. 335, 343 (E.D.Mich.1995). The fundamental problem with Mr. Pohler’s approach is that “[a]nyone can look at the same” map “and come up with a different” opinion. Ayers, 887 F.Supp. at 1060 .

Moreover, Mr. Pohler’s pipeline-proximity study failed to consider whether the leases or acreage associated with Exxon’s 369 gas properties and the Ellis gas properties were located “in a solid block or scattered.” Hugoton I, 161 Ct.Cl. at 320-21 , 315 F.2d at 894 ; Hugoton II, 172 Ct.Cl. at 449 -50 n. 7, 349 F.2d at 420 -21 n. 7. As noted above, this factor, or sub-factor, enters into the gas comparability determination because the internal geographical configuration of the producer’s leases or acreage is a determinant of the size and cost of the gathering system that must be built in order to effectuate the delivery of the gas to the buyer’s pipeline. Hugoton I, 161 Ct.Cl. at 320-21 , 315 F.2d at 895 ; Hugoton II, 172 Ct.Cl. at 450 , 349 F.2d at 421 ; Panhandle, 187 Ct.Cl. at 156, 223 , 408 F.2d at 707 . We certainly perceive no rational justification for Exxon’s failure to address the internal geographical configuration of its own gas properties. Further, given the availability of the gas purchase contracts pertinent to most of the Ellis transactions, it was undeniably feasible for Mr. Pohler to have considered the internal geographical configuration of the leases or acreage associated with many of the Ellis gas properties. 94

Despite the aforementioned shortcomings in Mr. Pohler’s analysis, the various maps in the record clearly demonstrate the great number and density of the pipeline systems operating in 1975 throughout the Texas Gulf Coast area, i.e., “Pipeline Alley,” and, to a lesser yet nonetheless substantial extent, in the East Texas area. None of Exxon’s 369 gas properties or the Ellis gas properties was situated more than roughly ten miles from a pipeline, and the vast majority of such gas properties was located only one to two miles from one or more pipelines. Thus, it is evident to the naked eye that gas producers throughout the Texas Gulf Coast/East Texas region enjoyed convenient access to nearby pipelines. 95 Consequently, although we are unable, on this record, to make any general statement regarding the internal geographical configurations of the gas properties in issue, 96 the court nevertheless finds that Exxon’s gas properties were reasonably comparable, on the average, to the Ellis gas properties, in terms of their proximity to pipelines operating in the Texas Gulf Coast/ East Texas region in 1975.

e. Hydrogen Sulfide Content

Hydrogen sulfide is a poisonous gas that sometimes contaminates raw natural gas.

*632 Gas containing excessive amounts of hydrogen sulfide is termed “sour gas,” whereas gas containing acceptable amounts of hydrogen sulfide is termed “sweet gas.” See Panhandle, 187 Ct.Cl. at 156, 223 , 408 F.2d at 707 ; Exxon I, 33 Fed.Cl. at 256-57 . Sour gas makes poor fuel, because hydrogen sulfide is extremely toxic, highly corrosive in the presence of water, and, when burnt, emits a rotten-egg odor. Shamrock, 35 T.C. at 988, 1016 . Thus, in gas purchase contracts, pipeline companies typically specify a maximum hydrogen sulfide content of one-quarter grain per hundred cubic feet of gas, which equates to about four parts per million. Sour gas can be “sweetened” by various chemical treatments in order to reduce its hydrogen sulfide content to tolerable levels. Due to the cost of treating sour gas to make it usable as fuel, sweet gas tends to command a eommensurately higher price.

Based upon his personal experience as the gas supply coordinator of the Exxon Gas System from 1973 to 1986, Mr. Pohler testified that only about 0.2% of the Exxon gas in issue was sour gas, i.e., gas containing more than the maximum one-quarter grain of hydrogen sulfide per 100 cubic feet that was permitted by pipeline gas quality specifications. 97 In contrast, based upon hydrogen sulfide content data obtained from the Dwights database, Mr. Pohler determined that at least 3% of the Ellis gas, in volumetric terms (Mcf), was sour gas. Therefore, with regard to hydrogen sulfide content, Mr. Pohler concluded that the Exxon gas in issue was of higher quality, on the average, than the Ellis gas in issue. Inasmuch as Mr. Pohler’s determinations are uncontroverted, the court agrees. The mere fact that a very small proportion of the gas in issue was sour gas does not bar a finding of comparability. See Panhandle, 187 Ct.Cl. at 156 , 408 F.2d at 707 (finding “[s]ome very small accumulations of sour gas” in the relevant market area, yet concluding that comparability had been sufficiently demonstrated). Accordingly, we find that the Exxon gas well gas in issue was of higher quality than the Ellis gas well gas in issue, in terms of hydrogen sulfide content.

f. Btu Content

In the natural gas industry, the heating value of gas is measured in terms of Btu content. Hugoton I, 161 Ct.Cl. at 293 , 315 F.2d at 879 ; Panhandle, 187 Ct.Cl. at 156, 222-23 , 408 F.2d at 707 . 98 The Btu content of natural gas depends upon its chemical constituency. As noted above, the principal component of natural gas is methane, the lightest gaseous hydrocarbon. Raw natural gas produced in the Texas Gulf CoasVEast Texas region is, on the average, approximately 90% methane, with the remaining 10% being constituted of the heavier, liquefiable hydrocarbon components, i.e., “natural gas liquids” such as ethane, propane, butane, pentane, etc., and contaminants such as oxygen, nitrogen, carbon dioxide, and hydrogen sulfide. Not all raw gas is average in terms of Btu content, however. Rather, a distinction must be made between gas well gas, produced by gas wells, and casinghead gas, produced by oil wells. Casinghead gas ordinarily contains a lower proportion of methane and higher proportions of natural gas liquids. 99 See Exxon I, 33 Fed.Cl. at 256 (similar finding as to 1974). Therefore, inasmuch as natural gas liquids are richer fuels than methane, ie., possessing greater heating values, casinghead gas typically has a significantly higher Btu content than gas well gas.

Given two equal volumes of raw gas, produced from two different wells, the volume of gas with the higher Btu content tends to be the more valuable of the two. Panhandle, 187 Ct.Cl. at 156 , 408 F.2d at 707 ; Exxon I, *633 33 Fed.Cl. at 258 (“Generally, the higher the Btu per Mcf at the well head, the more valuable the gas is....”). The foregoing relationship between the heating value and the dollar value of a given volume of gas is most evident when gas is priced and sold volumetrically, i.e., on a price-per-Mcf basis. By the early 1970s, however, the natural gas industry had largely moved away from the traditional volumetric method of pricing gas, in favor of “Btu pricing.” Given that natural gas is predominantly bought and sold for its heating value, ie., as fuel to be burned, Btu pricing acknowledges that Btu content is a more accurate measure of value. Under Btu pricing, gas is typically priced and sold on a price-per-MMBtu (million Btu) basis, which tends to negate price disparities between high-Btu and low-Btu gas. The diminished significance of Btu content as a gas pricing criterion was noted in the litigation over Exxon’s 1974 RMFP, as follows:

Another change in the industry was the shift in 1974, from Mcf-based to Btu-based pricing. This shift eliminated the distinction for pricing purposes, between processed and unprocessed gas. There were no premiums paid for high Btu content or for processed or unprocessed gas. Gas was considered gas and the only thing that mattered, other than reserve size and de-liverability, was whether or not the gas met pipeline specifications.

Exxon I, 33 Fed.Cl. at 261 (emphasis added). Here at bar, the record establishes the continued predominance of Btu pricing in 1975. Further, as in 1974, gas prices under contracts with Btu pricing terms were not materially influenced by distinctions between high-Btu and low-Btu gas in 1975. As Mr. Eakin put it, under Btu pricing, “gas is gas and Btu is Btu.” Tr. 619. 100

However, notwithstanding the ascendancy of Btu pricing in the 1970s, the RMFP of natural gas has always been calculated and expressed in traditional volumetric terms, i.e., as a price per Mcf. See Exxon I, 88 F.3d at 979 ; Panhandle, 187 Ct.Cl. at 160, 175 , 408 F.2d at 709, 718 . We see no compelling reason to depart from the foregoing convention, here at bar, inasmuch as the parties have prepared and submitted their respective RMFP computations in terms

This text is long and has been trimmed here. Open the source document for the complete record.