Swift, Judge:
The issue for decision is whether Petroleum Revenue Tax (PRT) petitioners paid to the United Kingdom for 1983 through 1988 constitutes, for U.S. income tax purposes, a creditable income or excess profits tax under section 901 or a creditable tax in lieu thereof under section 903.
Unless otherwise indicated, all section references are to the Internal Revenue Code in effect for the years in question, and all Rule references are to the Tax Court Rules of Practice and Procedure.
FINDINGS OF FACT
The parties have stipulated numerous facts and admissibility of numerous exhibits. The stipulated facts are so found.
During the years in issue, petitioners constituted an affiliated group of more than 175 U.S. and 500 foreign subsidiary corporations. Petitioner Exxon Corp. was the common parent of the affiliated group, with its principal place of business in Irving, Texas. Hereinafter, petitioners will be referred to simply as Exxon.
The businesses in which Exxon was engaged primarily involved exploration for and production, refining, and sale of crude oil, natural gas, and other petroleum products.
Exxon’s North Sea Licenses
The North Sea presents one of the harshest working environments in the world. As of the mid-1960’s, oil and gas companies had not attempted production of oil and gas in conditions as severe and difficult as those that existed in the North Sea, and oil and gas companies generally lacked experience and technology to explore for and to recover oil and gas from the North Sea.
Under Article 2 of the Geneva Convention on the Continental Shelf, Apr. 29, 1958, 15 U.S.T. 473 (ratified in the United States Apr. 12, 1961), various countries were granted jurisdiction and control over seabed areas adjacent to their coastlines. Individual treaties were negotiated between countries bordering the North Sea to fix boundaries between their respective offshore areas.
In the Continental Shelf Act, 1964, ch. 29, sec. 1 (Eng.), the United Kingdom implemented provisions of the 1958 Geneva Convention on the Continental Shelf with regard to the United Kingdom portion or segment of the North Sea. Hereinafter, such portion or segment will be referred to simply as the North Sea.1
In May of 1964, the United Kingdom first issued to oil and gas companies licenses for exploration of and, if commercial oil and gas reserves were discovered, for development and production of oil and gas resources in the North Sea. The next three United Kingdom license rounds relating to the North Sea took place in August of 1965, September of 1969, and June of 1971. During these four license rounds, crude oil prices generally remained at approximately $3 per barrel.
In 1970, oil discoveries were reported in the North Sea. However, oil reserves in the North Sea remained unproven. The North Sea was considered a marginal oil prospect, and oil production did not begin in the North Sea until 1975.
In the first four license rounds, the United Kingdom offered areas that covered almost all of the North Sea, but oil and gas companies did not apply for most of the areas because of the risks and uncertainties involved. Of the areas offered, applications for licenses were received for only 35 percent of the areas. Licenses for a number of areas not applied for when first offered included what in later years became the largest and most profitable oil-producing fields in the North Sea.
The areas that turned out to be the most significant oil fields in the North Sea were licensed by the end of the fourth license round in 1971.
With regard to North Sea petroleum resources, the United Kingdom generally used a discretionary licensing system under which the United Kingdom selects oil companies to which licenses are issued from a pool of companies that apply for the licenses. This enabled the United Kingdom to further governmental objectives such as rapid and appropriate exploitation of North Sea petroleum resources. In contrast, under an auction licensing system, licenses are issued to the highest bidders, who are not necessarily the most financially sound or competent companies to develop petroleum resources associated with the licenses.
Further, at least in the 1960’s and early 1970’s, due to uncertainties and risks associated with exploitation of North Sea petroleum resources, it was generally expected that with regard to the North Sea resources, the United Kingdom would not raise as much revenue from an auction licensing system as from a discretionary licensing system.
In June of 1971, as part of the fourth license round that was generally conducted on a discretionary basis, the United Kingdom experimented with an auction system and invited bids for 15 areas. The winning bid (by Exxon and Shell) for one of the auctioned areas (involving a field adjacent to where Exxon and Shell had already discovered oil) was for £21 million, but the average bid price with respect to the remaining 14 areas that were available under the auction was less than £1.2 million.2
At the time, in the 1960’s and early 1970’s, the United Kingdom concluded that the financial terms of the discretionary North Sea licenses that it issued to Exxon and to other oil and gas companies were appropriate for the particular circumstances of the United Kingdom, which at the time had virtually no indigenous oil and gas production and which was in competition with other countries for resources that the oil industry would allocate to the North Sea.
Since the fourth license round in 1971 in which the United Kingdom had experimented with an auction licensing system, the United Kingdom has continued to use, with limited exceptions, a discretionary licensing system. The United Kingdom and most major oil-producing countries other than the United States rely primarily on discretionary licensing systems with regard to the recovery of petroleum resources.
Generally, under the discretionary licenses issued by the United Kingdom for exploitation of North Sea petroleum resources, terms of the licenses required licensees to pay to the United Kingdom up-front fees based on the size of the areas subject to the leases followed by escalating annual fees and a 12V2-percent royalty based on gross value of total oil and gas production at the wellhead. The 121/2-percent royalty rate was approximately the same as the royalty rate that was used by most oil-producing countries throughout the world. The terms of the licenses also required the licensees to conduct seismic survey work and to drill a specified number of exploratory wells.
Royalties due under the North Sea licenses issued by the United Kingdom were allowed to be paid in kind by the oil companies.
To actually operate in the North Sea, oil and gas companies holding licenses were required to pay the license fees and royalties and to complete exploratory work programs specified in the licenses.
During 1972 and early 1973, the Public Accounts Committee (PAC) of the U.K. House of Commons held hearings on U.K. tax and energy policies with regard to the North Sea. At the time, there were indications that crude oil prices might increase significantly, although the price increases that later occurred as a result of the 1973-74 Arab oil embargo were not anticipated.
In February of 1973, PAC issued a report summarizing the discretionary licensing system that primarily had been used by the United Kingdom for the first four license rounds for the North Sea. In the 1973 report, PAC made no recommendation that the discretionary licensing system be changed to an auction system or that the 121/2-percent royalty rate associated with North Sea licenses be increased.
In the 1973 report, PAC also reviewed the then-existing U.K. corporation tax applicable to oil company profits to be earned from North Sea oil and gas and expressed concern that the U.K. corporation tax was poorly structured in that petroleum companies could offset profits from North Sea oil and gas activity by losses from unrelated activities. PAC also recommended legislative changes to the U.K. corporation tax to increase the effective U.K. tax rate on profits relating to North Sea oil and gas production. In that report, no recommendation was made to impose a tax similar to the PRT.
In October of 1973, war broke out in the Middle East, leading to the embargo by the Organisation of Petroleum Exporting Countries (opec) on exports of crude oil to the United States and, by the end of 1974, to a fivefold increase in world crude oil prices.
During 1974, the U.K. economy was experiencing a serious recession with high inflation and severe balance of payments problems. Because of the United Kingdom’s dependence on imported crude oil, the 1974 increase in the price of crude oil exacerbated the United Kingdom’s fiscal crisis. As a result, in July of 1974, the U.K. Secretary of State to Energy issued a report to the U.K. Parliament (1974 White Paper) in which it was concluded that unless the United Kingdom modified its tax regime, the United Kingdom would receive only a small portion of North Sea oil and gas company profits. In the 1974 White Paper, it was also recommended: (1) That the United Kingdom modify its tax regime with regard to North Sea oil and gas production activity in order to, among other things, eliminate the ability of oil and gas companies to offset profits from North Sea operations by losses realized by the companies elsewhere in the world, and (2) that the United Kingdom assert increased control over oil and gas companies’ North Sea operations.
No recommendation was made in the 1974 White Paper to make any significant change to the United Kingdom discretionary licensing system for the North Sea.
Between 1976 and 1988, there were seven additional license rounds conducted by the United Kingdom relating to the North Sea.
Over the years, North Sea licenses were issued and administered, and the related fees and royalties were collected, by the U.K. Ministry of Power, the U.K. Department of Technology, the U.K. Department of Energy, and the U.K. Department of Trade and Industry. At no time have North Sea licenses been administered, or have the related fees and royalties been collected, by the U.K. Treasury or by the U.K. Inland Revenue.
Significant uncertainties, risks, and investment commitments for Exxon were associated with Exxon’s North Sea licenses — risks that insufficient oil deposits would be discovered, that oil resources that might be discovered would not be commercially exploitable, and that the large capital and operating costs associated with exploring for and developing oil and gas resources in the North Sea would be lost.
The licenses between the United Kingdom and Exxon regarding North Sea petroleum resources were entered into in good faith. They were negotiated at arm’s length. They constituted enforceable contracts under U.K. law.
License fees and royalties that have been collected by the United Kingdom from oil and gas companies with regard to North Sea petroleum resources have constituted a substantial source of income to the United Kingdom.
Through 1992, Exxon has paid to the United Kingdom more than £16 billion in royalties in connection with the North Sea licenses it received. Under the licenses Exxon received and taking into account risks and costs associated therewith at the time the licenses were issued, the fees and royalties Exxon paid to the United Kingdom for the licenses to exploit North Sea petroleum resources constituted reasonable and substantial compensation therefor.
Ring Fence Tax and PRT
As indicated, during the Arab oil embargo world crude oil prices increased approximately fivefold. As a result, in 1975, out of concern that the U.K. corporation income tax might fail effectively to tax anticipated extraordinary profits to be realized by oil and gas companies, the U.K. Government enacted a new tax regime on income earned from oil and gas recovery activities in the North Sea. The new tax regime consisted of the ring fence provisions of the U.K. corporation income tax (Ring Pence Tax) and PRT. The Ring Fence Tax and PRT replaced the U.K. corporation income tax as it otherwise would have applied to activities of oil and gas companies in the North Sea.
The purpose and objective of the United Kingdom in enacting the Ring Fence Tax and PRT were to accelerate tax revenues relating to development of North Sea petroleum resources and to tax extraordinary profits of oil and gas companies relating to the North Sea.
To make it more difficult for oil and gas companies to offset profits derived from the North Sea with losses and expenses from unrelated activities, the Ring Fence Tax was enacted as a modified or customized version of the U.K. corporation income tax and was made applicable to activity of oil and gas companies in the North Sea in lieu of the general provisions of the U.K. corporation tax generally applicable to U.K. corporate taxpayers.
The Ring Fence Tax applies3 only to companies producing oil and gas and to related activities in the North Sea, and it erects a “ring fence” around oil and gas activities in the North Sea by requiring oil and gas companies to segregate income and expenses attributable to North Sea activity from income and expenses attributable to activity unrelated to the North Sea.
The Ring Fence Tax was enacted under the U.K.’s sovereign taxing power, and under U.K. law it constitutes a tax on income.
The Ring Fence Tax is structured as a corporate income tax.
Along with other U.K. taxes such as the U.K. corporation income tax and the Ring Fence Tax, under U.K. law, PRT was intended, is structured, and is regarded as a tax. PRT was imposed unilaterally by the United Kingdom and was administered as a tax by the U.K. Inland Revenue.
With regard to North Sea oil and gas recovery activities, the Ring Fence Tax and PRT are imposed in substitution for, and not in addition to, the generally applicable U.K. corporation tax. Oil and gas companies operating in the North Sea are liable, with regard to such activity, for the Ring Fence Tax and PRT, not for the otherwise generally applicable U.K. corporation tax.
In order to provide uniform administration of the Ring Fence Tax and PRT, in 1975 the Oil Taxation Office of the U.K. Inland Revenue was established and was delegated that responsibility.
The fees and royalties due under the licenses issued by the United Kingdom to Exxon and other oil and gas companies regarding the North Sea were not modified, supplemented, or altered by the PRT that was enacted in 1975.
Gross income relating to North Sea oil and gas recovery activities, with limited exceptions, constitutes the tax base for PRT, and losses relating to activity outside the North Sea ring fence are not allowed to offset income from activity occurring within the North Sea ring fence. PRT is imposed on income relating to extraction of oil and gas from the North Sea, income earned by taxpayers providing transportation, treatment, and other services relating to oil and gas resources in the North Sea (tariff receipts), and income relating to sale of North Sea assets (disposal receipts).
Interest income, income from sales of purchased and resold crude oil, and income relating to sale of gas exempt from PRT liability are not included in the income base for PRT purposes.
In computing net profits for PRT purposes and on which PRT liability is calculated, all significant costs and expenses, except interest expense, of producing taxable income relating to North Sea petroleum resources are currently deductible. To prevent the use of intercompany debt as a means of avoiding or minimizing liability under the Ring Fence Tax and PRT, deductions for interest expense are limited under the Ring Fence Tax and are not allowed under PRT.
Initial calculations of profits under PRT are made at the field level, with current deductions from gross revenue generally allowed for all ordinary as well as capital expenses relating to the field. Current deductions are allowed for, among other things, costs of exploration and appraisal activities, startup activities, operations, production, storage, treatment, transportation, administrative and overhead activities, buildings and structures (if placed on the seabed or used in production, measurement, transportation, or initial treatment and storage of petroleum products), and abandonment activity relating to a field, as well as costs of conducting arm’s-length sales of petroleum products and of exploring and evaluating areas outside a field that do not result in discovery of new fields.
As indicated, under PRT, current deductions are not allowed for interest expense, and current deductions are not allowed for costs of acquiring licenses from private parties, for payments to private parties holding overriding royalty and similar interests in a field, for expenses incurred in producing income exempt from PRT, and for payments of tax that should have been paid by foreign contractors providing services to the taxpayer in the North Sea.
Under PRT, operating losses from any period are carried back or carried forward without, limit to income associated with the field.
Additional prominent features of PRT, as originally enacted and as amended over the years, may be described generally as follows:
(1) As an incentive to development of marginal North Sea fields, an “oil allowance” or exemption from PRT is allowed for each field in an amount equivalent to the value of 500,000 metric tons of. oil per 6-month period up to a total of 10 million metric tons over the life of the field;4
(2) A tariff receipts allowance is allowed, which for each 6-month chargeable period exempts from PRT tariff receipts attributable to transportation of up to 250,000 metric tons (i.e., up to 1,875,000 barrels) of oil from each field;
(3) Various non-field-specific expenses are deductible against income from a field (e.g., exploration, appraisal, and research expenses);
(4) As a limit on the amount of PRT that would be owed, a “safeguard” provision limits the amount of PRT payable in each 6-month period in which it applies except to the extent that adjusted profits from a field exceed 15 percent of accumulated capital investment in a field and then PRT only applies to 80 percent of such adjusted profits;
(5) An exemption from PRT is allowed for revenue relating to North Sea natural gas production derived from pre-July 1975 contracts with the British Gas Corporation;
(6) Upon abandoning fields, carryover of unused losses are allowed without limit to other North Sea fields;
(7) PRT was enacted as a “prior charge” to the Ring Fence Tax which means that PRT is computed, assessed, and paid before the Ring Fence Tax, and PRT is deductible in computing the Ring Fence Tax;
(8) Of the limited types of expenses that are not allowed as deductions for PRT purposes, interest expense is the only nonallowable expense that is significant, and in lieu of interest expense, a deduction is allowed for “uplift” (discussed further, infra).
Because of the above features of prt, activities in a North Sea field generally are not subject to PRT until they reflect a cumulative profit.
PRT liability of a company is to be paid only in cash, not in kind.
On a number of occasions, in response to changes in world oil markets and in order to make certain adjustments to prt, provisions of PRT were amended by the United Kingdom. Such amendments that, over the years, have been made to prt are not particularly significant to the issue before us and generally are not described herein.
As indicated, in order to minimize prt avoidance through intercompany interest charges, interest expense deductions relating to North Sea oil and gas recovery activities are not allowed in computing prt liability. Current deductions from income, however, are allowed for what is referred to as uplift, consisting of amounts equal to 35 percent of most capital expenditures relating to a North Sea field (over and above the current deductions allowed in computing PRT for 100 percent of such capital expenditures).5 The deduction for uplift is provided in lieu of a deduction for North Sea related interest expenses.
Similar to the cost of capital expenditures to which uplift relates and on the basis of which uplift is calculated, uplift is allowable in full as a current deduction at the time the related capital expenditures are incurred and fully deducted. Allowances for uplift are computed and determined only during the period of time prior to when an activity in a field becomes profitable, the period during which interest expense relating to a field typically is necessary. Once calculated and determined, unused uplift may be carried back or carried forward without limit.
In calculating Exxon’s PRT liability for 1975 through 1988, the cumulative total amount of uplift deduction allowed to Exxon was £1.8 billion, almost twice the cumulative total £900 million interest expense that under PRT was not allowed as a deduction to Exxon.
Based on industry data that is in evidence and that was gathered from Exxon and approximately 33 other oil companies involved in North Sea oil and gas production, the cumulative total uplift allowed the companies for 1975 through 1988 was £12.4 billion, as compared to cumulative total interest expense not allowed the companies under PRT of £8.6 billion. In the appendix to this Opinion, for 1975 through 1988, we set forth the amount of uplift and other deductions allowed to Exxon and to the other oil and gas companies and the amount of ring fence interest expense not allowed to Exxon and the other oil and gas companies in the computation of PRT liability.
As a result of the special allowances such as oil, tariff receipts, safeguard, and uplift, PRT represents and constitutes a tax on a subset of net income subject to the Ring Fence Tax.
Through 1992, Exxon had interests in 23 oil-producing North Sea fields, but significant PRT was paid only with regard to 5 of the fields (Brent, Forties, Dunlin, Fulmar, and North Cormorant). More than 60 percent of total PRT paid by Exxon through 1992 was paid with respect to only one field— the Brent field, which was the highest oil-producing field in the North Sea. Generally for the industry, the bulk of PRT was paid with respect to a limited number of the largest and most profitable fields. More specifically, through 1988, approximately 75 percent of total cumulative PRT collected by the United Kingdom was paid by only five oil and gas companies which owned the largest and most profitable fields in the North Sea.
Because of the special allowances, small oil and gas companies with interests in marginal fields typically owe no PRT with regard to fields licensed to them.
Preexisting licensees (i.e., companies such as Exxon to whom North Sea licenses were issued prior to enactment of PRT in 1975) were obligated to pay PRT upon its enactment in 1975 and in subsequent years even though they were in full compliance with terms of their pre-1975 North Sea licenses. All prt paid by Exxon during the years in issue and the character of which is in dispute in these cases was paid by Exxon with respect to fields licensed to Exxon before 1975 and before prt was enacted.
As a result of paying prt, Exxon neither received any special benefits under the North Sea licenses that it had been issued before 1975, nor received any special benefits from the United Kingdom in obtaining new North Sea licenses after 1975.
By 1979, with the rise of oil prices relating to the Iranian Revolution, there was a general perception that the prt rate was too low and that the United Kingdom ought to be collecting more PRT from oil companies operating in the North Sea. In 1982, however, with a drop in world oil prices, there was a general perception that the prt rate was too high and that PRT and increased operating costs were becoming a disincentive to North Sea oil and gas development activity.
As a result of the above increases and decreases in world oil prices and the changing perceptions regarding prt and the PRT rate, in 1979, 1980, 1982, and 1993 the tax rate for PRT was changed from the original rate of 45 percent as enacted in 1975 to the rates indicated:
1979 1980 1982 1993
PRT rate 60% 70% 75% 50%
In 1993, prt was eliminated for all subsequent North Sea oil and gas activity under licenses to be issued thereafter, and, as indicated, the PRT rate was reduced to 50 percent for existing licenses.
For 1975 through 1988, Exxon paid £3.5 billion in PRT, approximately 11 percent of the approximate total £32 billion in PRT that was paid to the United Kingdom by all oil and gas companies for those years.
Because primarily of timing differences associated with calculations of prt at the field level and because PRT was deductible in computing the Ring Fence Tax, for any 1 year companies may owe PRT but no Ring Fence Tax, they may owe Ring Fence Tax but no PRT, and they may owe both PRT and Ring Fence Tax or neither. These differing results are not inconsistent with the objective of PRT to tax extraordinary profits and to accelerate tax revenues relating to development of North Sea petroleum resources.
OPINION
With limitations not here pertinent, taxpayers may claim credits under section 901 against their Federal income taxes for, among other things, the amount of income and excess profits taxes paid to foreign countries. See sec. 901(b)(1). As an exemption from tax, the credit provisions of section 901 are to be strictly construed. See Inland Steel Co. v. United States, 230 Ct. Cl. 314, 677 F.2d 72, 79 (1982); Bank of Am. Natl. Trust & Sav. Association v. United States, 61 T.C. 752, 762 (1974), affd. without published opinion 538 F.2d 334 (9th Cir. 1976).
Under regulations applicable to the years in issue, foreign levies are to be regarded as income or excess profits taxes if they satisfy two tests: (1) The foreign levies constitute taxes, and (2) the predominant character of the taxes is that of an income tax in the U.S. sense. See sec. 1.901—2(a)(1), Income Tax Regs.
Generally, governmental levies imposed by and paid to foreign countries are to be treated as taxes if they constitute compulsory payments pursuant to the authority of the foreign countries to levy taxes. The regulations, however, also provide that foreign levies will not be regarded as taxes to the extent that payors of the levies receive specific economic benefits, directly or indirectly, from the foreign countries in exchange for payment of the levies. See sec. 1.901-2(a)(2), Income Tax Regs. The regulations also provide that economic benefits that foreign Governments do not make available on substantially the same terms to substantially all persons subject to the generally imposed income tax (such as a concession to extract Government-owned petroleum) will be regarded as specific economic benefits. See sec. 1.901-2(a)(2)(ii)(B), Income Tax Regs.
Exxon acknowledges that the licenses it received from the United Kingdom to exploit North Sea petroleum resources constitute the receipt of specific economic benefits and therefore that Exxon is to be treated under the regulations as a “dual capacity” taxpayer and as subject to the regulations with regard thereto under sections 1.901-2(a)(2) and 1.901-2A, Income Tax Regs. Thereunder, dual capacity taxpayers (who pay levies and who also receive specific economic benefits from the Government) have the burden to establish the extent, if any, to which foreign levies they pay constitute taxes — as opposed to payments for the specific economic benefits received — by relying either on the regulations’ safe harbor method or on the facts and circumstances method. See sec. 1.901-2A(c)(1) and (2), Income Tax Regs. Exxon herein relies on the facts and circumstances method, and Exxon is required to establish, under all of the relevant facts and circumstances associated with its payment of PRT, what portion, if any, of PRT paid by it to the United Kingdom constitutes taxes, as distinguished from payments in exchange for the license rights it received.6 See sec. 1.901-2A(b) and (c), Income Tax Regs.
With regard to the second test involving the predominant character of the foreign taxes, the regulations provide, among other things, that foreign taxes will be treated as income taxes in the U.S. sense if the foreign taxes operate in such a manner as to reach net gain in the normal circumstances in which they apply. See sec. 1.901-2(a)(3)(i), Income Tax Regs. More specifically, the regulations provide that foreign taxes will be treated as income taxes if and only if the taxes, judged on the basis of their predominant character, satisfy each of the realization, gross receipts, and net income requirements of section 1.901-2(b), Income Tax Regs.
Generally, under section 1.901—2(b)(4)(i), Income Tax Regs., foreign taxes will be regarded as satisfying the net income requirement if, measured by their predominant character, they permit recovery of the significant costs and expenses relating to the income or if they provide other allowances that effectively compensate for nonrecovery of such costs and expenses.7
The regulations also provide that taxes either are or are not to be regarded as income taxes in their entirety for all persons subject to the taxes. See sec. 1.901-2(a), Income Tax Regs. Respondent does not interpret this provision as requiring that, in order to qualify as an income tax, a tax in question must satisfy the predominant character test in its application to all taxpayers. Rather, respondent interprets this provision as requiring that in order to qualify as an income tax a tax must satisfy the predominant character test in its application to a substantial number of taxpayers.
On brief, respondent explains the net income test as follows: PRT satisfies the net income test if its base is computed by reducing gross receipts to permit recovery of significant costs and expenses attributable to gross receipts, or, if some of these costs and expenses are not deductible, recovery of such costs and expenses computed under a method that is likely to produce an amount approximating or exceeding the nondeductible costs or expenses.
The parties have stipulated that PRT meets the realization and gross receipts requirements of section 1.901-2(b)(2) and (3), Income Tax Regs., that PRT constitutes a compulsory payment imposed by the United Kingdom within the meaning of section 1.901-2(a)(2)(i), Income Tax Regs., and that PRT does not constitute a soak-up tax within the meaning of section 1.901-2(c), Income Tax Regs. The only issues before us are whether PRT paid by Exxon is to be treated as a tax (as opposed to payment for specific economic benefits) and whether the predominant character of PRT may be regarded as an income tax in the U.S. sense and thereby as satisfying the net income test.8
PRT and Compensation for Specific Economic Benefits
The evidence in these cases establishes that PRT paid by Exxon does not constitute compensation in exchange for license rights or other specific economic benefits received by Exxon. Upon enactment of PRT and upon or in exchange for payment of PRT, Exxon was granted no additional rights, under its licenses or otherwise, with respect to North Sea petroleum resources. Exxon’s rights to explore for, develop, and exploit petroleum resources in the North Sea during the years in issue arose from and were dependent upon licenses Exxon obtained from the United Kingdom in prior years (before PRT was enacted) and on Exxon’s payment to the United Kingdom of license fees and royalties due under those licenses.
The United Kingdom’s purpose in enacting PRT in 1975 was to take advantage of rising oil prices and to ensure that the United Kingdom realize an appropriate share of excess profits to be realized by Exxon and by other oil and gas companies from exploitation of petroleum resources in the North Sea under the licences granted to them.
License fees owed and paid by Exxon under terms of the discretionary licenses (consisting of the up-front fees, annual fees, and 12V2-percent royalties) represented substantial and reasonable compensation to the United Kingdom for the licenses. As indicated, through 1992 the oil and gas companies have paid to the U.K. Government more than £16 billion in royalties alone in connection with the North Sea licenses.
Under its sovereign taxing power, the United Kingdom intended to and did impose PRT as a tax, not as payment for specific economic benefits. Respondent stipulates that PRT was not negotiated but was imposed unilaterally, as a compulsory payment, and that PRT was enacted and is administered as a tax under U.K. law — all characteristics of taxes, not of payments for specific economic benefits.
The parties herein rely heavily on expert witnesses — from the petroleum industry, from the U.K. Government, and from legal, tax, accounting, and economic professions — as to the character of PRT as a tax or as payment for specific economic benefits.
The basis of the opinions rendered by respondent’s economic experts seems to be that, in hindsight, oil companies “got a good deal” when they entered into North Sea license agreements, that the licenses turned out to be more valuable than anyone anticipated at the time the licenses were issued, and therefore that the oil companies “probably felt there was an implicit contract” to pay some type of additional charges, and that these additional charges (whatever they may be called, however they are administered, and regardless of their features) should be regarded as what respondent’s expert witnesses refer to as “economic rent” (i.e., as deferred payments in exchange for the licenses granted in earlier years to the oil companies) and not as taxes.
Respondent’s experts overemphasize the fact that North Sea licenses issued by the United Kingdom to the oil and gas companies in the late 1960’s and in the 1970’s were issued largely without an auction system. As we have found, throughout the world most countries traditionally have not relied on auction systems to issue licenses for the right to exploit petroleum resources.
In considering North Sea licenses Exxon received and under which it operated in the North Sea, respondent’s experts fail to recognize and to give proper weight to the significant uncertainties, risks, and investment commitments associated with oil and gas exploration and production in the North Sea that, at the time the licenses were issued to Exxon, were associated with the licenses — risks that insufficient oil and gas deposits in the North Sea would be found, that petroleum resources that might be discovered would not be commercially recoverable, and that the large investments required to explore for oil and gas and to operate in the North Sea would be lost.
Respondent’s experts speculate that in light of increased oil prices in the late 1970’s and early 1980’s, the United Kingdom could have set the license fees higher and obtained higher revenues under the North Sea licenses. That, however, is not the proper inquiry. We are not particularly concerned with speculation about whether in retrospect the United Kingdom extracted all the revenues it could have from oil companies under the licenses. Rather, as Exxon’s witnesses emphasize, the proper focus is whether PRT was imposed and paid “in exchange for” North Sea license rights. This is the focus of the regulations under section 901 and that focus is to be maintained here. See sec. 1.901-2(a)(2), Income Tax Regs; see also Phillips Petroleum Co. v. Commissioner, 104 T.C. 256, 297 (1995).
In Phillips Petroleum Co., we held that Norway’s Special Tax on oil and gas activity in the Norwegian sector of the North Sea constituted, for U.S. Federal income tax purposes, a creditable tax under section 901. Norway’s Special Tax is similar in a number of significant respects to PRT.
Under temporary Treasury regulations applicable to the years involved in Phillips Petroleum Co., Norway’s Special Tax was to be treated as a tax as long as “no significant part of the charge [represents] compensation for the specific economic benefit received”. See sec. 4.901—2(b)(2)(iii), Temporary Income Tax Regs., 45 Fed. Reg. 75649 (Nov. 17, 1980), as applicable to 1979 to 1982. Applying that test, we held in Phillips Petroleum Co. v. Commissioner, supra at 289-297, that Norway’s Special Tax constituted a tax and not payment for specific economic benefits.
The Norwegian Special Tax was enacted in 1975 and was imposed on oil and gas companies operating under discretionary licenses granted by Norway requiring payment of initial fees, annual fees, and 10-percent royalties. We concluded that by payment of the Special Tax the oil and gas companies were not granted additional rights under their licenses, that the fees and royalties paid under the licenses represented substantial compensation for such licenses, that the Special Tax constituted a tax and not an additional royalty, and that the purpose of the Special Tax was to impose taxes on excess and unexpected profits, not to impose additional charges on oil companies for rights to extract oil, and therefore that the Special Tax constituted a tax, not a levy in exchange for specific economic benefits. In Phillips Petroleum Co. v. Commissioner, supra at 295, we explained:
The word “tax” in [the U.S.] * * * is generally understood to mean an involuntary charge imposed by legislative authority for public purposes. It is exclusively of statutory origin. Tax burdens and contractual liabilities are very different things. A tax is compulsory, an exaction of sovereignty rather than something derived by agreement. A tax is a revenue-raising levy imposed by a governmental unit. It is a required contribution to the governmental revenue without option to pay. A royalty refers to a share of the product or profit reserved by an owner for permitting another to use a property. [Citations omitted.]
In Phillips Petroleum Co., we then concluded that the Norwegian Special Tax was enacted:
to take advantage of a new profit situation created by surging oil prices, and to receive a larger share of what Norway saw as extraordinarily high and unforeseen profits generated from Norwegian resources, and at the same time to allow petroleum companies to earn a reasonable profit. [Id. at 292.]
Phillips Petroleum Co. v. Commissioner, supra, supports our finding and conclusion herein that PRT is not to be regarded as payment in exchange for specific economic benefits Exxon received under its North Sea licenses.
All of the PRT the character of which is in dispute in these cases was paid by Exxon with respect to oil production from fields licensed to Exxon before 1975 and before PRT was enacted. As one of respondent’s experts acknowledges, Exxon did not receive any special benefits under its licenses, or otherwise, for paying PRT, and Exxon in later years, as a result of paying PRT, did not receive any special advantages in obtaining additional North Sea licenses.
The credible and persuasive evidence strongly supports and we conclude that all PRT paid by Exxon for the years in question constitutes taxes, not payments for specific economic benefits.
PRT and the Net Income Test
The purpose, administration, and structure of PRT indicate that PRT constitutes an income or excess profits tax in the U.S. sense. The provisions of PRT include in the tax base, with limited exceptions, income earned from North Sea related activity and permit allowances, reliefs, and exemptions that effectively compensate for nondeductibility of certain oil company expenses, particularly interest.
Although a deduction is not allowed for interest expense related to North Sea operations, uplift, oil, safeguard, and tariff receipts allowances provide sufficient relief to offset for nonallowance of a deduction for interest expense. See sec. 1.901-2(b)(4)(i), Income Tax Regs. For 1975 through 1988, representative industry data indicate that oil companies received uplift allowances alone of £12.4 billion as compared to North Sea related interest expense not allowed of £8.6 billion.
Evidence at trial covering approximately 88 percent of total oil production in the North Sea and 98 percent of total PRT paid by oil companies during 1975 through 1988 shows that special allowances and reliefs under PRT significantly exceed the amount of disallowed interest expense for Exxon and other oil companies. These special allowances and reliefs reduce the base of PRT to a subset of net income representing excess profits and establish that, in its predominant character, prt constitutes and is to be treated as an income tax.
Although PRT does not allow a deduction for interest expense — certainly a significant expense — under the special provisions allowed (particularly uplift), the oil companies are provided under PRT allowances that effectively compensate for the nondeductibility of interest expense.
As explained by the Government official who on April 10, 1975, first presented for formal legislative consideration the proposed Ring Fence Tax and PRT to the U.K. House of Lords: “In fact, of course, this tax [PRT] represents an excess profits tax.”
Respondent’s experts assert that uplift provides too “crude” a substitution for a deduction for interest expense, that prt fails to provide an allowance that “mimics” interest expense, and that the relationship of PRT allowances to nonrecoverable expenses is not sufficiently “predictable”. We reject these labels as merely argumentative and as without merit.
We note statements in respondent’s pretrial brief, in respondent’s counsel’s opening statement, and in a number of respondent’s experts’ reports or testimony that in essence acknowledge the “income” or “profits” nature of PRT. One of respondent’s experts testified contrary to prior published statements he has made regarding PRT and its nature as an “excess profits tax”.
In Texasgulf, Inc., & Subs. v. Commissioner, 107 T.C. 51 (1996), affd. 172 F.3d 209 (2d Cir. 1999), we held that the Ontario Mining Tax (omt) satisfied the net income test of the section 901 regulations and constituted a creditable income tax. Among other things, we relied on industry data showing that a special processing allowance available to taxpayers in computing OMT liability adequately compensated for significant nonallowed costs, including interest. The evidence, among other things, indicated that the processing allowance, in the aggregate for the industry, exceeded the amount of significant nondeductible costs. See id. at 66.
On appeal, the Court of Appeals for the Second Circuit focused on how OMT applied to the mining industry as a whole and on return-by-return data (rather than on aggregate industry data on which this Court in its opinion in Texasgulf, Inc., & Subs., had focused) and affirmed this Court’s opinion. Noting that only 33 percent of the income tax returns showed nonrecoverable expenses in excess of the processing allowance and that, of the income tax returns that reflected OMT liability, only 16 percent showed nonrecoverable expenses that exceeded the processing allowance, the Court of Appeals concluded that the taxpayer had met its burden of proving that under omt the taxpayer was effectively compensated for nonrecoverable costs.
In its opinion in Texasgulf, Inc., & Subs. v. Commissioner, 172 F.3d at 216, the Court of Appeals for the Second Circuit expressly noted that, where available, quantitative and empirical evidence relating to taxpayer and to industry experience in calculating and paying foreign taxes is appropriate and relevant in analyzing the net income requirement. The Court of Appeals explained as follows:
the language of sec. 1.901-2—specifically, “effectively compensate” and “approximates, or is greater than” — suggests that quantitative empirical evidence may be just as appropriate as qualitative analytic evidence in determining whether a foreign tax meets the net income requirement. * * * [Id.]
In Texasgulf, Inc., & Subs. v. Commissioner, 107 T.C. at 64-65, 70, we used similar language to describe the type of evidence that may be used in evaluating the nature of foreign taxes for purposes of section 901. See also Texasgulf, Inc., v. United States, _ Fed. Cl._(Oct. 15, 1999).
Credible expert witness testimony, industry data, and other evidence in these cases establish that allowances available under PRT effectively and adequately compensate Exxon for expenses disallowed under PRT and that PRT, in its predominant character, constitutes a tax in the nature of an excess profits tax (i.e., an income tax) in the U.S. sense.
Respondent contends that Exxon’s industry data is biased in favor of large oil and gas companies like Exxon and that a company-by-company analysis indicates that a majority of the companies operating in the North Sea for a majority of years did not have uplift allowance greater than or equal to nonrecoverable interest expense. As Exxon points out, however, respondent’s approach ignores the fact that PRT was designed to tax excess profits from North Sea oil and gas production which generally were earned by major oil and gas companies which owned the largest and most profitable fields in the North Sea. Through 1988, approximately 75 percent of PRT was paid by only five major companies. Small companies with licenses for marginal fields, because of the special allowances, typically owe no PRT, and for companies which owe no PRT it is irrelevant whether uplift is adequate to offset non-allowed interest expense. Through 1988, 34 of the 79 oil companies included in the studies paid no PRT.
We agree with Exxon that if a company-by-company approach is used to analyze the effect of uplift and other allowances, some particular focus should be given to those companies which earn excess profits from North Sea oil production and which pay PRT. This is the type of empirical and particular industry data that would seem particularly relevant. Of the 45 companies which through 1988 paid approximately 98 percent of total PRT paid to the United Kingdom, 34 companies or 76 percent (and accounting for 91 percent of total PRT paid through 1988) had uplift allowance in excess of nonallowed interest expense. If the oil allowance is factored into the data, 39 of 45 companies or 87 percent (and accounting for 94 percent of total PRT paid through 1988) had allowances in excess of nonallowed interest expense.
We conclude that PRT constitutes a tax, that the predominant character of PRT constitutes an excess profits or income tax in the U.S. sense, and that PRT paid by Exxon to the United Kingdom for the years in issue is creditable under section 901 against Exxon’s U.S. Federal income tax liability.
In light of our resolution of the above issues, we need not address Exxon’s alternative argument that PRT qualifies under section 903 as a creditable tax in lieu of an income tax.
To reflect the foregoing,
Decisions will be entered under Rule 155.
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