Phillips Petroleum Co. v. Commissioner

104 T.C. No. 12, 104 T.C. 256, 1995 U.S. Tax Ct. LEXIS 13

Opinion

Korner, Judge:

By statutory notice of deficiency dated July 10, 1991, respondent determined deficiencies in the Federal income tax of Phillips Petroleum Co. and its affiliated subsidiaries (hereinafter Phillips or petitioners) for the taxable years 1979 through 1982 as follows:

Year Deficiency

1979 . $59,029,820

1980 . 61,528,138

1981 . 47,572,045

1982 . 5,536,203

All statutory references are to the Internal Revenue Code in effect for the years in issue, and all Rule references are to the Tax Court Rules of Practice and Procedure, except as otherwise noted. After concessions and the severance of certain issues, the sole remaining issue for decision here is whether three separate charges paid by petitioners to the Kingdom of Norway during the years 1981 and 1982 qualify as “income, war profits, or excess profits taxes” or taxes “in lieu” thereof, so that they are creditable pursuant to section 901 or 903.

FINDINGS OF FACT

1. Background

Some of the facts are stipulated and so found. The stipulations of facts and accompanying exhibits are incorporated herein by this reference. Phillips was incorporated in Delaware on June 13, 1917. Phillips’ principal place of business at the time of filing the petition herein was Bartlesville, Oklahoma. During the years in question, petitioners were engaged primarily in acquiring, exploring, developing, and operating oil and gas properties, as well as refining and ^marketing petroleum products.

By Royal Decree, the Kingdom of Norway on May 31, 1963, proclaimed its sovereignty over the seabed and the subsoil of the Norwegian Continental Shelf in the North Sea. Norway cites this decree as one basis for its authority over the exploitation of and the exploration for natural deposits within these territorial boundaries as well as its jurisdiction to tax such resources. The Norwegian Parliament, known as the Storting, by Act No. 12 on June 21, 1963, enacted a law vesting ownership in the Kingdom of all Norwegian natural submarine resources (including petroleum), and authorizing the King to grant rights of exploration and exploitation to Norwegian or foreign persons (including foreign companies).

The King, by Royal Decree of April 9, 1965, and pursuant to the above Act, set forth rules and regulations for the conduct of petroleum operations on the Norwegian Continental Shelf and delegated to the Royal Ministry of Industry and Handicraft, later known as the Ministry of Petroleum and Energy (hereinafter Ministry of Petroleum or Petroleum Ministry) the power to grant production licenses to foreign companies, the power to regulate licensees, and the power to impose conditions on licensee operations.

The Petroleum Ministry divided Norway’s Continental Shelf into blocks, each bounded by 15 minutes of latitude and 20 minutes of longitude. The blocks were further divided into fields. In general, areas to be opened to licensing were publicly announced in the official Norwegian Gazette. Such announcements delineated required terms, particularly fee information. Each prospective licensee could apply for a grant to any number of fields within one or more blocks; however, the total area licensed was to be regarded as a single unit for purposes of regulation.

Licenses were not awarded pursuant to competitive bidding in the sense that the bidder offering top dollar would be successful. Instead, the Petroleum Ministry granted licenses based on an evaluation of information contained in prospective licensees’ applications, including, among other things, the geological and geophysical information upon which the application was based, an applicant’s previous experience in the petroleum industry, including exploration, exploitation, refining, and marketing capabilities, as well as an applicant’s financial position, evidenced by financial statements and annual reports for the prior 3 years (presumably indicating an applicant’s ability to fund the immense amount of capital required to successfully undertake offshore petroleum exploration and exploitation). The Petroleum Ministry was not obligated to grant a license on the basis of applications received, should none of the applicants prove acceptable.

As required by the regulations, Phillips established a Norwegian branch office in Oslo, Norway, with a permanent representative domiciled in Norway, fully authorized to enter into binding commitments, or to otherwise act on Phillips’ behalf. On August 17, 1965, a group of producers known as the Phillips Group was granted production license Nos. 016, 017, and 018. The Phillips Group at that time included petitioners, Norske Fina A/S, and Norsk Agip A/S. The license area encompassed a total of 1,758 square kilometers, and was located in the southern part of the Norwegian sector of the North Sea; this area became known as the Ekofisk area. Through the years in issue, the Phillips Group produced commercial quantities of petroleum from license No. 018 only.

Phillips incorporated Phillips Petroleum Co. Norway (Phillips Norway) in Delaware on August 23, 1968, as its wholly owned subsidiary. Phillips transferred its interest in license No. 018 to Phillips Norway with the Petroleum Ministry’s consent on November 12, 1968. Thereupon, Phillips Norway became the operator for the Phillips Group. For the years in issue, Phillips Norway was an exploration and production company which had no sales, marketing, or refining capabilities.

With respect to license No. 018, the members of the Phillips Group and their respective ownership interests, during the years in issue, were as follows: Phillips Norway (36.96 percent); Norske Fina A/S (30 percent); Norsk Agip A/S (13.04 percent); Elf Aquitaine Norge A/S (8.094 percent); Norsk Hydro Produksjon A/S (6.7 percent); Total Marine Norsk A/S (4.047 percent); Eurafrep Norge A/S (0.456 percent); Comparex Norge A/S (0.399 percent); and Cofranord A/S (0.304 percent). Members of the Phillips Group were not related to Phillips, except for Phillips Norway. Other members represented countries such as Norway, Belgium, Italy, and France. From the date of transfer through the years in issue, Phillips Norway and its coventurers held the exclusive license or right to explore for and exploit petroleum deposits in the Ekofisk area.

Licensees were subject to regulations governing the conduct of petroleum exploration and exploitation operations in the seabed and subsoil of the Norwegian Continental Shelf, decreed on April 9, 1965, and to any conditions included in their license grant. Production licenses were valid for an initial 6-year term. Licenses were granted with the Petroleum Ministry’s approval only upon a prospective licensee’s written acceptance of a 6-year work program. Work programs were licensee specific and in this case required the Phillips Group to conduct seismic surveys and to drill a total of five wells within the areas covered by their license grant. Major deviations from work programs required written approval from the Petroleum Ministry. If, for any reason, a work program was not fulfilled, the Ministry could demand payment for the estimated cost of the unexecuted portion of the work obligation. Sanctions for violating Norway’s petroleum regulations or license grant conditions included the temporary halting of operations or license revocation in the case of serious or repeated violations such as the failure to timely pay fees, royalties, or any other payments. Additional 40-year extensions were available only to licensees who had fully complied with their work program requirements.

License No. 018 was initially valid through August 31, 1971. The Phillips Group’s license grant was subsequently renewed for an additional 40-year term, a term that was set to expire September 1, 2011. Additional license extensions could be obtained if a deposit continued to be productive beyond the combined 46-year term.

When a production license was granted, licensees were liable for a nonrecurrent fee at a rate of 500 Norwegian kroner (NKr) per square kilometer of area granted. Phillips Group paid NKr879,000 on 1,758 square kilometers. If a licensee was successful in extending the initial 6-year term, then the licensee became liable for annual area fees, which were paid in advance. The annual area fee was similarly calculated, but the rate increased NKr500 per year until it peaked in the 10th year, and so remained thereafter, at NKr5,000 per square kilometer.

During each year of production, the licensee was also liable for a royalty charge. The regulations effective at the time of petitioners’ grant of license No. 018, as well as petitioners’ actual license grant, provided for a royalty payment due in the amount of 10 percent of the gross value at the wellhead on the amount of petroleum extracted and saved, but not on the amount used for production purposes. Upon 3 months written notice, the Ministry could require the royalty to be paid in kind instead of in cash, in part or wholly. The Ministry of Petroleum required the Phillips Group to pay their royalties in kind beginning in 1974, and has continued this requirement to date and throughout the years in issue.

For 1981 and 1982, Phillips Norway paid the following area fees and oil, natural gas, and natural gas liquid (NGL) royalties, for production from license No. 018 in NKr, as represented below in U.S. dollar equivalents, or in kind.

Year Area fees ($) Oil Natural gas royalties royalties (bbl’s) (mcf) Natural gas royalties ($) Natural gas liquid royalties ($)

1981 528,201 4,425,767 9,020,349 27,676,881 2,631,335

1982 468,411 3,720,289 12,218,656 18,441,524 4,333.140

The above area fees and royalties paid in NKr and represented above in U.S. dollar equivalents are represented below in NKr.

Natural gas Natural gas liquids Year Area fees (NKr) royalties (NKr) royalties (NKr)

1981 3,011,057 157,774,648 15,000,170

1982 3,011,057 118,546,392 27,854,431

In calculating the amount of royalty due, the area fee was deductible in full unless a licensee failed to exploit finds or discontinued exploration of areas granted. In other words, no royalty was due until such royalties exceeded the amount of the area fee.

Norwegian petroleum regulations required all installations, pipelines, shipment and other facilities to meet with the Ministry of Petroleum’s consent and conditions. The King also required produced petroleum to be landed in Norway unless some other landing point was approved. Due to the fact that pipeline laying technology and engineering experience (at that time) would not ensure that a pipeline could be timely, economically, or successfully constructed in the North Sea across the Norwegian trench, the Phillips Group sought and successfully obtained a concession from the Ministry of Petroleum on May 4, 1973, to construct and operate a pipeline for transporting a mixed stream of crude oil and NGL from Ekofisk Center (a centrally located processing center) to be landed at Teesside, near Tees, in the United Kingdom (U.K.), and another pipeline for transporting natural gas from Ekofisk Center to be landed at Emden, in the Federal Republic of Germany.

From the time of production through the landing of crude oil at Teesside, Phillips Norway along with others owned their pro rata share of crude oil produced from license No. 018 (excluding the 10-percent royalty obligations which were taken in kind by Norway beginning in 1974). The bulk of incoming crude oil was loaded onto oceangoing tankers and exported. What was not immediately exported was piped another 3 miles to a refinery, also at Tees, in which Phillips held a 50-percent interest. For the first time in 1975, Norway became a net exporter of petroleum.

During the years in issue, Phillips Norway had neither refining nor marketing capabilities; therefore, Phillips Norway contracted to sell 100 percent of its Ekofisk oil production to its parent, Phillips. The price exchanged for such oil (at least since January 1, 1981) was contracted to be the norm price established by the Norwegian Petroleum Price Board (see infra sec. 2) and effective when oil passed the delivery point at the Teesside terminal. Because this oil would be sold before the norm price was set, a provisional price would be agreed to between the parties, and payment would be due 30 days from the bill of lading date for each cargo of oil delivered at Teesside. During the years in issue, Phillips made cash payments to Phillips Norway for crude oil sales. Any difference in the norm price and the provisional price was adjusted upon announcement of the norm price.

2. Norm Price System

The norm price system was established pursuant to the Norwegian Petroleum Tax Act (PTA), Act No. 35, on June 13, 1975. Section 4 of the PTA provided that for purposes of tax assessment and royalty charges not taken in kind, the King, generally or in particular cases, could determine, with binding effect, a norm price for-petroleum produced from Norway’s Continental Shelf. Recognizing itself as a country of small size and limited resources, and further recognizing that petroleum exploration and exploitation was being undertaken by large, fully integrated international corporations, Norway established the norm price system to solve the problems and complexities it perceived to be associated with determining specific sales prices for crude oil transfers that were occurring predominantly between affiliates of such companies. In its recommendation to the Storting, the Ministry of Finance (the agency in charge of legislative tax proposals and tax administration) was clearly concerned that, compared to the enormous resources of these large international petroleum companies, Norway could not mar-shall the staff of experts or resources necessary to undertake the taxpayer-by-taxpayer determinations that were required to establish true prices, as compared to those reported for transfers that were not subject to ordinary market forces. Such determinations required inquiries into whether common interests existed between buyers and sellers of petroleum, the formation of well-founded opinions on how prices were actually influenced by such relationships, and support for correct prices. Norway viewed such endeavors as enormously expensive, time consuming, seemingly unenforceable, and a nearly impossible administrative burden. Against this background, the norm price system was enacted.

The Ministry of Finance was aware that such a system would lead to different results among companies, depending on the efficiency with which their operations were conducted. It introduced such a system to solve the above-referenced problems of administration and control. The following guidelines were set forth for the purpose of achieving a correct price, that is, a price which could occur between independent parties under free market conditions.

The PTA and subsequent regulations issued by Royal Decree on June 25, 1976, mandated that each norm price would be equivalent to the price at which petroleum could have been sold between independent parties in a free market. Independent parties were defined as buyers and sellers who did not manifest common affiliations that could influence an agreed price. In determining a norm price, factors that were required to be considered included realized and quoted prices for petroleum of the same or similar type, adjusted for quality variations, transport cost differences, delivery, payment, and other term disparities; realized and quoted prices for refined petroleum products, adjusted for variations in the costs of processing, etc. (parity prices); and other comparable prices. Consideration was also to be given to any other circumstances that could affect price, including influences involved in agreements between affiliated companies.

The King delegated to the Ministry of Petroleum the authority to determine norm prices and the further authority to delegate this responsibility to a special Petroleum Price Board (hereinafter board or ppb). The members of the ppb were appointed by the King. Subsequent to 1980 amendments, the board consisted of six members. At least five of these six members were required to be present to conduct business, and a consensus of five was required to adopt resolutions. One individual each represented the Ministry of Petroleum and the Ministry of Finance. The remaining four members were nominated by the Petroleum Ministry and were appointed in their personal capacities. None of the members were representatives of the petroleum industry. The stated term of office for each member was 2 years. However, due to the complexity and volatility of the petroleum market, continuity in the composition of the board was desirable, so to a large extent members were repeatedly reappointed. The present chairwoman of the board has been a member since March 1980.

For the years in issue, the PPB determined norm prices retroactively twice a year for two quarters at a time and for crude oil alone. The Petroleum Ministry found that norm price determinations were unnecessary for natural gas and NGL, as common affiliations between the producers and purchasers of these products were found not to exist to an extent that prices were significantly affected thereby. The norm price was not an official selling price but an ex post facto price set after the expiration of the pricing period.

Those subject to norm prices were not only obligated to furnish all information the board was required to consider pursuant to the PTA and the norm price regulations, but were also encouraged to submit any additional information they considered significant to the norm price determination. Those subject to norm price determinations were required every month to submit special price statement forms for all transfers or “liftings” of petroleum produced from the Norwegian Continental Shelf. These forms required the history of each cargo to be disclosed including sale or exchange terms, the date and size of each shipment, the place and terms of delivery, the quantity delivered, the name and relationship with the buyer (if any), credit terms, and the price per barrel. The secretariat of the PPB compiled these pricing statements, arranging them by month and crude oil type, thereby giving the PPB an overall picture of all liftings for each period.

In addition to the PPB’s price statement forms, the Phillips Group would submit its own proposal to the PPB. In contrast to other countries around the world that incorporate a system of administratively determined prices, the determination of norm prices in Norway was both a participatory and an adversarial process. Close contact and thorough discussions between the PPB and the petroleum companies were envisioned and achieved prior to the board’s final norm price determination. The Phillips Group participated aggressively in this process, not only because its taxable receipts, and thereby its tax liability, would indirectly flow from such determinations, but also to glean an insight into the board’s workings so that the Phillips Group could better predict the factors the board considered significant to its norm pricing determinations, and also so that the group could better present its position.

Where petroleum was produced on the Norwegian Continental Shelf by two or more cooperating companies, as was the case for the Phillips Group, the PPB could and did require a joint submission on behalf of the group as a whole. With the Phillips Group, each member performed different tasks in preparing for the Phillips Group norm price presentation. Phillips, due to its marketing and sales expertise, drafted each submission with supporting data compilations on behalf of Phillips Norway. The entire Phillips Group would then meet to discuss, and would arrive at a compromise position reconciling the various conflicting interests among group members, regarding the content and tone of each submission.

For each norm price determination, the Phillips Group would submit a lengthy and detailed presentation to the board setting forth the complexities involved in the international petroleum market, the group’s perception of the most significant market influences, an evaluation of the Norwegian crude oil market and other relevant market areas, as well as international events that affected the market for Norwegian crude, and transaction evidence for each quarter including weighted average calculations of third-party sales prices achieved by group members (long-term contract obligations and spot transactions), other producing countries’ official selling prices, and theoretical processor parity calculations, all ultimately culminating in a joint proposal of an average price at which Ekofi.sk area crude oil could have been sold during each quarter; that is, the group’s norm price recommendation or proposal. Phillips Group submissions generally emphasized realized third-party sales prices; that is, actual spot and contract prices.

The submissions made by the petroleum companies were important sources of information for the PPB. The secretariat also provided the PPB with market reports regarding international energy prices and supply, consumption, and production level evidence, together with many other market publications. Additionally, the PPB engaged independent expert consultants to supply market surveys and prepare parity prices. Parity prices were product prices at varying degrees of refinement reduced by estimated costs of such refinement, and adjusted for differentials in quality, crude oil type, and freight charges. They were prepared in order to compare different types of crude oils and their product yield values. The Ministry of Petroleum recognized that parity prices would be of somewhat limited value, given the number of assumptions and differing opinions involved in such calculations, but the PPB considered them particularly useful in the 1970’s at a time when Norway’s oil industry was emerging and no established market existed for North Sea crude oils. Parity prices were considered evidence of market value to a lesser degree by 1981 and 1982.

The board’s procedure for determining provisional and final norm prices began with a meeting where all of the above information including pricing information, recommendations from the petroleum companies, the secretariat’s market studies, consultant’s studies, and all other market evidence was presented and considered by the board members. The board would then hold a meeting for 1 or 2 days where market information was discussed with representatives of each submission. Following this meeting, the PPB would announce a provisional norm price position which would typically be expressed as a price range. The range generally varied from 10 to 20 cents per barrel, depending on the board’s perception as to the reliability of or uncertainty with the type of market information before it.

After the board’s provisional determination, the parties were given a second opportunity to address the board to further advance their positions with additional evidence or argument and to draw attention to factors they believed should be given closer attention before the final price determination was made.

The ppb’s norm price decisions were not based on predetermined formulas but were discretionary determinations derived from each member’s consideration of all concerns expressed, and relevant evidence presented, with the directive that such price reflect the price at which petroleum could have been sold between independent parties in a free market during the period in question. This standard was designed to reflect a wide market concept; it was not limited to the examination of one market segment. The flexibility in this standard was designed to allow board members to consider all factors as they became relevant, and to attach varying weights to different value indicators, as quickly as the fluctuating petroleum market dictated. No individual factor or a single category of transactions would normally be reflective or decisive of value. It was the board’s purpose and intention to mirror the market as it changed. In its norm price determinations, the PPB disregarded internally priced, non-arm’s-length transactions. For the years 1981 and 1982, the number of arm’s-length third-party sales were few.

From 1975 through 1979, norm prices were determined for crude oil production from the Ekofisk area alone. Crude oil production from the Statfjord and Murchison areas began in 1979 and 1980, respectively. For 1980, the PPB established norm prices for two Norwegian North Sea crude oil producing areas, Ekofisk and Statfjord. For 1981 and 1982, the PPB also established norm prices for a third Norwegian North Sea crude oil producing region, Murchison. The following table shows Phillips Group’s proposed norm prices, the provisional range of prices, and the final norm prices set by the PPB for crude oil produced from the Ekofisk area for each quarter of 1981 and 1982.

Provisional Final Phillips Group’s Provisional norm price norm proposed norm norm price range price

1981

40.00 1st 39.90 39.95-40.10 H

39.30 2d 38.70 39.30-39.50 (N

35.75 3d 35.60 35.65-35.80 H

36.75 4th 36.55 36.65-36.80 H

1982

35.05 1st 34.64 35.10-35.30 N

32.50 2d 32.40 32.40-32.60 (M

34.15 3d 34.07 34.10-34.25 H

34.00 4th 33.86 34.00-34.20 Cv|

Those subject to norm prices could appeal the ppb’s norm price determination with the Petroleum Ministry within 30 days of a decision. An appealing party could also demand that the matter be referred to a committee of experts for comment, before the Petroleum Ministry decided the merits of an appeal. The expert committee consisted of three members appointed by the Chief Justice of Norway’s Supreme Court. This committee determined whether the ppb’s price determination was obviously inequitable, but it could not adopt a new norm price resolution.

In no case has an expert committee found a contested norm price to be obviously inequitable. In one instance, such committee found the norm price determination to be too high. The committee’s opinion was not binding on the Petroleum Ministry. Whenever there was an appeal, the Ministry of Petroleum was obligated to reconsider its original decision. The standard of review was whether the ppb’s norm price determination was obviously unreasonable. The decision of the Ministry of Petroleum was the final administrative decision upon which a petroleum company could appeal further to the Norwegian Courts of Justice.

From the institution of the norm price system in 1975 through 1993, there were 20 separate appeals. During the 1980 and 1981 period, there were two appeals of norm price determinations for the second quarter of 1981. One appeal was registered for the Ekofisk area, and one for the Statfjord area. Only once, during the third quarter of 1986 and for all three crude oil streams (Ekofisk, Statfjord, and Murchison) did the Ministry of Petroleum reverse the ppb’s norm price determinations. One court action was initiated but was ultimately dropped.

The realization of income for Norwegian tax purposes occurred for petroleum producers as petroleum passed the designated place of delivery (the norm price point). The Petroleum Ministry designated the assumed place of delivery for Ekofisk crude as FOB Teesside, U.K.; therefore, petroleum from the Ekofisk area that was to be loaded on ship passed the norm price point upon completion of loading at Teesside. For petroleum to be refined in Tees, the norm price point was the pipeline terminal at Teesside, U.K. Once petroleum passed the norm price point, tax liability was established, even if the oil was disposed of other than by sale. After the PPB determined the norm price, gross income was assessed accordingly by the Ministry of Finance, and liability accrued in arrears. A corporation’s gross income from petroleum sales, therefore, was not based on actual invoice prices. The final norm price was used as the actual price for tax purposes, but the PPB had no authority to require or suggest that those subject to norm prices charge norm prices upon disposition of their oil. In fact, as noted above, the PPB norm prices were used by Phillips and Phillips Norway as actual sales prices.

The norm price was substituted for actual sale prices, including sales between unrelated parties, and was the common price for all petroleum passing the norm price point during the quarter regardless of the disposition of such petroleum. It was an average price not in the sense that it was determined pursuant to a structured formula but in the sense that when applied to quantities of crude produced, such price ideally would generate an amount of income that was equivalent to what could have been reported by all producers in the area pursuant to actual sales during that particular period.

3. Norwegian Tax Laws

The three separate charges relevant to this case include Norway’s municipal tax, national tax, and special tax.¹ On August 18, 1911, Norway adopted its General Tax Act (GTA), the basic law governing the taxation of income and capital for all individuals and corporations. Municipal and national charges (discussed below) generally applied to the worldwide income of Norwegian corporations and to the Norwegian source income of foreign corporations. The GTA provided Norway with jurisdiction to tax nonresident corporations that conducted, engaged, or participated in business or other economic activities carried on or administered within the realm or national territory of Norway.

(a) Norway’s Municipal Charge

Pursuant to the GTA, individual taxpayers were subject to the municipal charge in their district of residence. Norwegian corporations engaging in activities that generated income within a single district were liable for municipal charges in that district alone; however, corporations conducting activities spanning district lines were liable for municipal charges in each and every municipality or district where the corporation generated or was allocated net income. The Norwegian municipal rate of charge was derived from a combination of three rates payable as follows: (1) A municipal charge payable to the local government; (2) a county charge payable to the provincial government; and (3) a contribution to the tax equalization fund (created to redistribute tax revenues among municipalities). The total of the rates for these three segments of the municipal charge was designed not to exceed 23 percent. In each district, the total liability for the municipal charge was determined in a single calculation by applying the combined 23-percent rate to a single base of municipal taxable income.

Each year, corporations were required to prepare traditional comparative financial statements, including a balance sheet, a statement of sources and uses of funds, and an income statement. The income statement demonstrated in detail how a profit or loss was derived. Each item of income and expense was described and categorized with particularity in a manner similar to U.S. accounting standards. The calculation of the municipal tax base began with a corporation’s profit or loss. Corporations were required to hire one or more independent auditors, authorized or registered with the Norwegian Government to examine a taxpayer’s annual financial statements, accounts, and the general conduct of its business, and to submit a report to the corporation’s board of directors.

Norway provided for several individual and organizational tax exemptions, including the King, Royal Family, municipalities, churches, and not-for-profit organizations, as well as several benefit exemptions, including social security and veteran’s benefits.

Income and expenses were generally realized and incurred upon delivery of the asset or service sold. Pursuant to the GTA, income was realized or earned when an “advantage really passed to the taxpayer”; that was, upon the earlier of the right to demand payment, actual receipt of payment, or the rendering of an advantage or benefit. Benefits earned included capital gains from the sale of business assets. Where insurance proceeds from the accidental destruction of a major operating asset exceeded the adjusted basis of depreciated property, the benefit or gain could be exempted from tax where a taxpayer used such proceeds to acquire a new operating asset within 4 years of the loss.

Expenses were incurred and deductible on the date of payment. Expenses were deductible from gross income if incurred to acquire, secure, or maintain income. Deductible expenses specifically addressed in the GTA were interest on indebtedness, operating expenses, depreciation, business losses, and bad debts. Interest expenses were deductible by foreign companies only on debt that was incurred to promote activities in Norway. Annual changes in inventories, receivables, and debt were accounted for. Inventories were capitalized and accounted for at the lower of cost or market value at the end of an assessment period. Area fees and royalties paid by petroleum companies were deductible expenses. Those engaged in mining were allowed a deduction from gross income of a suitable percentage of the cost of the mineral deposit.

No special or separate Norwegian tax provisions considered the character of an item of income or expense relevant to its taxability. The taxation of financial income was treated in the same manner as operational income; each was included and taxed as a part of total income. For taxpayers with income in more than one district, however, the character of an item of income or expense determined among which tax district(s) such item would be allocated, and for which charges a taxpayer would be liable.

Income and expense items that were directly connected to a district were so allocated. Income derived from real estate or manufacturing plants was allocated to the district where such assets were located. Income generated from financial assets such as bank deposits, receivables, and debt, etc., was generally allocated to the onshore district in which a corporation’s main office was located. Expenses with no specific connection to an income source, such as central management costs and including interest charges, were allocated among districts based on proportionate net incomes. If a loss occurred after the allocation of interest expenses and similarly situated items, such loss was reallocated among income districts proportionately according to each district’s net income. Other expenses with some connection but not a direct connection to an income source were allocated based on a reasonable criteria standard.

In years prior to and including 1981, property, plant, and equipment of a sizable and permanent nature were depre-dable once taken into ordinary use, on a straight-line basis over useful lives established by the National Tax Board. The costs of assets that were not intended to be used or retained over the long term were currently deductible.

In 1981, the declining balance method was introduced as the method of depreciation. The straight-line method was allowable in 1981, and for the last time in 1982. Machinery, tools, fixtures, drilling vessels, etc., were depreciable at a 30-percent rate. Buildings and plants were depreciable at maximum rates of 8 or 12 percent, when the depreciable life was more or less than 20 years, respectively.

In addition to regular depreciation, an additional depreciation allowance was available for depreciable assets during the first 5 years of use. The total amount of additional depreciation could not exceed 50 percent of ordinary depreciation, and the annual allowance could not exceed 5 percent of a property’s cost.

Dividends distributed from a corporation’s net profits were not deductible in determining the base for the municipal charge. Dividend income was taxable in the main office district as allocated financial income.

A corporation could conduct several activities under one corporate enterprise, and such corporation was taxed as a single taxpaying entity. If a corporation derived profits in some municipalities and losses in other municipalities, any deficits would be allocated to income municipalities based on proportionate net incomes. Net operating losses (nol’s) could be carried forward 10 years and applied against subsequently received income.

A net operating loss generated by an affiliate conducting activities abroad was deductible against the income of a Norwegian affiliate only if the parent corporation owned at least 90 percent of a subsidiary’s stock and wielded the same degree of voting control, and also, if both companies were Norwegian joint stock companies. A joint stock company was defined as a company whose owners had shared or limited liability for obligations of the corporation and who owned shares of capital or were paid dividends. Phillips Norway was a Norwegian joint stock company; Phillips was not.

Where Norwegian tax authorities determined that a relationship or common interests existed between a Norwegian taxpayer and another entity, such that the prices exchanged for goods and/or services had been affected in a manner that reduced income, such authorities could disregard a taxpayer’s financial accounts and estimate income for tax assessment purposes.²

Municipal taxes were paid in four installments. The amount of each installment was established by local tax assessment offices based on the amount of tax assessed for the prior year. Installments were due on the 15th of February, April, September, and November of the year following the income year. The payment of taxes was deferred approximately 12 months from when income was earned.

(b) Norway’s National Charge

For the years in issue, all Norwegian taxpayers also were subject to a 27.8-percent charge, payable to the Kingdom of Norway and otherwise known as the national tax. The base for this charge was the same as that for the special charge (discussed below) except that dividends distributed were deductible to the extent of taxable income, and dividends received were allocated as income to this base of charge. Dividends could only be distributed from unrestricted accumulated net profits. Prior year’s losses and reserve account requirements were required to be met before dividends could be distributed. This deduction could substantially reduce a taxpayer’s liability for the national charge.

The municipal and national charges were referred to by the Ministry of Finance as Norway’s ordinary income taxes.

(c) Norway’s Special Charge

Norway enacted its first petroleum taxation law with Act No. 3 on June 11, 1965, the same year Norway’s first production licenses were awarded. This Act provided that income derived from submarine exploration and exploitation activities carried on in Norway would be taxed in the same manner as any other activity carried on in Norway; that is, according to Norway’s GTA and other general tax legislation. During 1973 and 1974, crude oil prices rose dramatically due, in part, to the Arab-Israeli War and the subsequent oil embargo. Between early 1973 and the end of 1974, prices for internationally traded crude oils jumped from approximately $2.15 to $10.50 per barrel. This very sharp rise in prices created an entirely new profit situation for petroleum companies and Norway. Petroleum revenues began far to exceed the high costs of risky petroleum operations in the Norwegian North Sea. Expressing the concern that Norwegian resources belonged to the Norwegian Kingdom and its people, the Storting determined that a larger share of these extraordinarily high and unforeseen profits should, like other national income, accrue to the Norwegian people. A proposal to increase royalty rates was deemed not feasible due to the legal difficulties involved in increasing rates agreed to pursuant to binding contracts, the unreasonable impact on marginal fields, and the perceived notion that rates would have to be increased to very high levels to obtain a satisfactory share of revenues. The Minister of Finance suggested that the most suitable way of increasing Norway’s share of profits was through a special tax on petroleum. The Minister of Finance recommended a new tax system to balance Norway’s concerns regarding control over its resources (in an economic and supply sense) with a system that would provide petroleum companies with a reasonable return after taxes. These considerations, as well as Norway’s admitted inexperience with a complex and very specialized international petroleum industry, precipitated the enactment of more comprehensive petroleum tax legislation, namely, the pta, by Act No. 35 on June 13, 1975.

The PTA applied to several activities, including the exploration and exploitation of Norwegian subsea petroleum deposits on the Norwegian Continental Shelf, pipeline transport of petroleum, and activities or work related thereto. The Norwegian Continental Shelf was designated a separate tax district known as the shelf district. Those taxed in and items allocated to onshore district(s) were not subject to the special charge. The PTA provided that those carrying on petroleum exploitation or pipeline transportation activities from installations in the shelf district were liable to the Norwegian Kingdom for the special charge on income derived from such activities. Foreign subcontractors and workers performing exploration activities or work related to the production or transport of petroleum, but not actual production activities, were not liable for the special charge, but were liable for the municipal and national charges onshore in their district of residence or where a company’s main office was situated. The PTA established municipal and national tax jurisdiction for such related work, but the special rules and charges of the PTA did not apply.

The rate of special charge was determined annually by the Storting. This rate varied over the years as substantial changes occurred in market outlook and industry profitability due to world oil price fluctuations. From 1975 through 1979, the rate of special charge was 25 percent, for the years 1980 through 1986, the rate was increased to 35 percent, during the period from 1987 through 1991, the rate was reduced to 30 percent, and since 1992 the rate was further increased to 50 percent.

The PTA provided that the rules of general tax legislation, including the GTA, continued to apply to those engaged in petroleum production or pipeline transportation unless overridden by contrary provisions of the PTA. Pursuant to the enactment of the PTA, those engaged in activities in the shelf district became expressly liable for Norway’s combined municipal charge; however, such revenue was payable to the Norwegian Government, which annually determined the amounts allocated to the onshore municipalities, provinces, and the tax equalization fund.

The most significant rule of the PTA for those conducting production or pipeline transport activities in the shelf district, involved norm price determinations.³ Gross income from petroleum activities conducted in the Norwegian Continental Shelf was assessed at norm price levels for quantities of oil passing the norm price point during each quarter of the year. Shrinkage that occurred after the norm price point was disregarded as a nondeductible loss. Phillips Norway sold all the crude oil it produced from the Norwegian Continental Shelf to its parent, Phillips, at norm price levels. All natural gas produced was sold to independent parties at contract prices. Sales of NGL were made at contract prices to both related and independent buyers. Inventories of petroleum that remained unsold upon passage of the norm price point were also valued at norm prices. Inventories were not given a value before passing this point. During the years in issue, Phillips Norway did not have inventories of petroleum products that were encompassed by this definition; that is, Phillips Norway sold its inventories of crude oil before or upon passage of the norm price point.

Those subject to the pta were governed by the same allocation rules that governed taxpayers subject to the GTA. Items allocated to onshore districts would subject taxpayers to the municipal and national charges, while items allocated to the shelf district would subject taxpayers to the special charge, in addition to the municipal and national charges (as modified by the pta). The allocation rules were amended in 1982 due to inconsistencies created by the addition of the offshore shelf district. Preamendment interest income and expense and currency gains and losses were allocated among the onshore and offshore districts, depending on the source or activity that generated the item. Specifically, financial income and losses were allocated to the main office district. However, debt-related currency losses and interest expenses were required to be allocated proportionately according to district net income, while other financial currency losses were allocated to the main office district. Currency gains and losses related to petroleum sales or receivables were directly related and, therefore, directly allocated to the shelf district. Currency gains related to debt that financed the acquisition of offshore facilities, however, were allocated to the main office district, but currency losses on such debt were regarded as interest and allocated proportionally among districts.

Pursuant to the 1982 allocation amendments, all similarly situated items of financial income and expense were required to be similarly allocated. The net of all items of financial income (gain) and expense (loss), including interest on debt, that were not directly related to a particular source of income, excluding dividends received, were allocated among all districts according to each district’s proportionate net income following the allocation of NOL’s. Dividends received continued to be alloc-'; ed and taxed in the main office district even though there was a close connection to the shelf district. Items directly related to petroleum production also continued to be so allocated.

Due to the physical location of petroleum operations in the North Sea, the shelf district had the character of a manufacturing district. When a taxpayer was engaged in petroleum production or pipeline transport of petroleum produced in the shelf district and was also carrying on another activity onshore, all capital, income, and deductions generated in the shelf district were effectively assessed as a separate activity or independent undertaking, accounted for, and taxed separately in the shelf district.

Pursuant to specific rules of the PTA, sales commissions, discounts, and related costs paid or allocated between petroleum companies where one enterprise participated directly or indirectly in the management, control, or capital of the other participant were specifically not deductible. The Ministry of Finance found that appreciable sales costs would not be incurred, and real sales did not occur, in transactions between members' of affiliated companies engaged in several related activities, including refining. The Ministry of Finance expressed concerns similar to those that precipitated the norm price system, specifically that it would be costly and difficult to substantiate actual costs abroad.

Gains from the disposal of assets acquired for use in petroleum production or transport could be exempted from municipal and national charges pursuant to the GTA, as well as from the special charge of the PTA, if such gain was allocated to a reinvestment fund and was actually reinvested in assets that were used in production or pipeline transportation activities.

No deduction was allowable for contributions made to institutions that conducted government-supervised scientific research.

The PTA provided special rules governing the depreciation of offshore production plants, pipeline transport facilities, and the fixed assets connected to such installations. Each production plant was regarded as a separate asset. The costs of acquiring production facilities and other offshore assets were required to be capitalized and depreciated. Interest expense on acquisition debt accrued prior to the commencement of depreciation for the asset was also capitalizable and depreciable at a taxpayer’s option. Taxpayers that chose to capitalize acquisition interest could also claim the additional uplift allowance (discussed below) for such costs. Exploration costs could be expensed as incurred. If a taxpayer chose to capitalize exploration costs, they were depreciable pursuant to the GTA rules, and such costs would not enjoy the accelerated depreciation rates provided by the PTA or the additional uplift allowance. Phillips Norway expensed all exploration costs as incurred.

Petroleum production plants, connected installation facilities, and all offshore fixed assets were considered to be taken into ordinary use and depreciable only upon the commencement of ordinary petroleum production. The maximum annual accelerated rate of straight-line depreciation for petroleum production, transportation facilities, and related assets was 16% percent over a minimum of 6 years. These accelerated rates of depreciation were considered reasonable due to the sizable investments, financing, and risks involved in North Sea petroleum production.

Additional depreciation allowances provided by the GTA were not available; however, an additional special deduction known as the uplift allowance was deductible in calculating the special and national bases of charge, but not the municipal base of charge. Norwegian authorities provided for this allowance out of concern for the high cost of development in the North Sea and the risks associated with unfavorable finds which would not generate a return on investment. Exploration expenses did not qualify. The allowance was limited to permanent offshore petroleum and pipeline installations, and assets connected therewith. Onshore assets did not qualify. The basis for the uplift allowance was the same as an asset’s depreciable basis, specifically, cost plus acquisition interest. The allowance was determined in the same manner as depreciation. Deductions could be taken in the year following the commencement of depreciation for an asset. Gains and losses upon disposition were also taxable events.

Prior to and during the years 1979 and 1980, the uplift allowance was deductible for 15 years at a 10-percent rate, resulting in a 150-percent additional deduction on investment. The allowance was tightened for the years 1981 and 1982, to promote cost consciousness by the oil companies, with a rate reduction to 6% percent. The 15-year period of deductibility remained unchanged, resulting in an eventual 100-percent additional allowance. Should the uplift deduction exceed a taxpayer’s taxable income, the deficit could be indefinitely carried forward against special charge assessments.

As with the municipal tax base, the special charge did not allow deductions for dividend distributions.⁴ Also, dividends received were not considered derived from petroleum production or transportation and, therefore, were more appropriately allocated to and taxed onshore in the main office district, as financial income.

Pursuant to the PTA, losses arising from petroleum activities in the shelf district — shelf losses — could be carried forward for a maximum of 15 years, as opposed to the 10 years provided by the GTA. Also, upon application by a taxpayer, tax authorities would generally agree to extra time to carry over shelf losses.

Shelf losses could offset, without limitation, income generated by a petroleum company in onshore districts in a manner proportionate to district net incomes. If as a result of such offsets a net loss among onshore districts occurred, such losses were not limited to the 10-year carryover period provided by the GTA, but could be carried over for 15 years. As an alternative to offsetting offshore deficits against onshore income, a taxpayer could choose to reserve offshore deficits as future carryovers to be utilized against subsequent offshore income, thereby reducing income which would otherwise be subject to the special charge, in addition to the municipal and national charges.

Onshore district losses were deductible against shelf district income, but such deduction was limited to 50 percent. The other 50 percent was not deductible against offshore income in subsequent years. Losses not deductible in the shelf district were deductible pro rata among onshore districts. Additionally, the 50-percent onshore loss deduction could be used only in determining the taxable bases of the offshore municipal and national charges; it was not deductible from the taxable base of the special charge.

Beginning in 1980, shelf taxpayers were required to pay the special tax in two installments, each constituting half of the estimated total tax assessment. The installments were due on October 1 of the income year and April 1 of the subsequent year, coinciding with norm price determinations, and resulting in an approximate 6-month deferral of taxation. Neither the pta nor the GTA provided license revocation as a remedy for the nonpayment of “taxes”. There were a variety of reasons why a licensee would make every effort to pay taxes in a timely manner. Delayed payment resulted in an interest claim that was normally higher than interest charged on an ordinary bank loan. Also, tax authorities demanding payment could force the sale of assets or a taxpayer could be forced into bankruptcy, whereupon a petroleum license could be revoked.

Petroleum companies subject to the PTA were not given compensation in the form of additional rights or in any other form for the increased tax burdens created by the special charge.

(d) Other Rules Applicable to Each Charge

None of the above three Norwegian charges, the municipal, the national, or the special charge, was deductible against the taxable base for either of the other charges. The rate for each charge was determined annually by the Storting’s National Resolution on Taxes.⁵ Taxes assessed against shelf taxpayers were administered by separate taxing authorities, namely the Petroleum Taxation Office, the Petroleum Taxation Board, and the Special Board of Appeal. Separate centralized taxing authorities were deemed necessary to administer this new and complicated industry, and to assure competence and uniformity in assessment. Assessments were proposed by the Petroleum Taxation Office and finalized by the Petroleum Taxation Board. The Special Board of Appeal ruled on all appeals under the PTA. The Petroleum Taxation Office was under the authority of the Ministry of Finance. Local assessment offices, boards, and appeal assessment boards administered onshore taxes and taxpayers unaffected by the PTA, as well as PTA taxpayers with income allocations generated from onshore districts.

4. Other

For 1981 and 1982, Norway reported total tax revenues pursuant to the above three Norwegian charges from all petroleum production and pipeline transport activities as follows:⁶

Billion NKr

Year Total charges 23% charge 27.8% national charge Special charge

1981 20,750 6,039 6,554 8,055

1982 22,918 6,622 7,224 8,985

5. Phillips Group’s and Phillips Norway’s Tax Returns

Phillips Norway filed 1981 and 1982 calendar year Norwegian corporate tax returns. For 1981, Phillips Norway reported financial income before taxes of NKr9,254,245,497 and reported municipal, special, and national taxable income in the respective amounts of NKr9,175,448,169, NKr7,748,415,171, and NKr8,103,756,681. At a 35-percent rate, Phillips Norway reported special taxes due in 1981 of NKr2,711,945,310. For 1982, Phillips Norway reported financial income before taxes of NKr9,146,306,305, and reported municipal, special, and national taxable income in the respective amounts of NKr8,824,878,514, NKr8,210,311,903, and NKr6,650,718,496. At a 35-percent rate, Phillips Norway reported special taxes due in 1982 of NKr2,873,609,166. After audit by Norwegian tax authorities, Phillips Norway’s 1981 and 1982 final Norwegian taxes were slightly increased. Phillips Norway paid Norwegian taxes for the years 1981 and 1982, in the equivalent U.S. dollar amounts of $1,220,454,482 and $956,486,685, respectively.

Phillips was the common parent of an affiliated group of corporations that included Phillips Norway. Phillips timely filed consolidated and Amended U.S. Corporation Income Tax Returns, Forms 1120 and Forms 1120X, for the taxable years ending December 31, 1981 and 1982. Petitioners’ U.S. corporation income tax returns for the years 1979 and 1980 are not in evidence. During the years in issue, petitioners claimed foreign tax credits against U.S. corporate income tax for taxes paid to Norway, limited by the provisions of the Internal Revenue Code only.

6. U.S.-Norway Tax Treaty

The first income tax treaty between the Kingdom of Norway and the United States was signed on June 13, 1949, and entered into force on December 11, 1951. Convention for the Avoidance of Double Taxation, June 13, 1949, U.S.-Nor., 2 U.S.T. 2323. This treaty was subsequently modified on July 10, 1958. Convention modifying the Convention for the Avoidance of Double Taxation, July 10, 1958, U.S.-Nor., 10 U.S.T. 1924. A new income and property tax treaty replaced this initial treaty. The new treaty was signed on December 3, 1971, entered into force on November 29, 1972, and became operative for tax years beginning on or after January 1, 1971. Convention for the Avoidance of Double Taxation, Dec. 3, 1971, U.S.-Nor., 23 U.S.T. 2832 (treaty). A later protocol amending the 1971 convention was signed on September 19, 1980, and entered into force December 15, 1981. Protocol Amending the Convention for the Avoidance of Double Taxation, Sept. 19, 1980, U.S.-Nor., 33 U.S.T. 2828 (protocol). This protocol was generally effective for the taxable years beginning on or subsequent to January 1, 1982. 33 U.S.T. at 2848.

Before amendment, Articles 1 and 23(1) of the U.S.-Norway treaty provided that double taxation of income regarding U.S. taxpayers would be avoided with the allowance of a credit against U.S. income tax, in the amount of certain taxes paid to Norway if such amounts were within the limitations of U.S. law. For purposes of applying such credit, Norway’s municipal and national charges were considered creditable income taxes. Also, taxes imposed in place of or in addition to existing taxes, and subsequent to the signing of the convention on December 3, 1971, would also be considered creditable income taxes if they were substantially similar to Norway’s municipal or national taxes. 23 U.S.T. at 2835, 2852.

The protocol amending Articles 1 and 23 provided that the Norwegian municipal and national taxes, as amended by the PTA, would continue to be considered creditable income taxes and that the Norwegian special tax also would be considered a creditable income tax, but that the amount of such credit would be limited. Credits would be subject to separate limitations as to the amounts of Norwegian taxes on oil and gas extraction income, other Norwegian oil-related income, and other foreign income, which were not to exceed the maximum statutory U.S. corporate tax rate during the tax years in issue. 33 U.S.T. at 2833-2834. These limitations are more commonly referred to as “per country” limitations. The above amendments were effective retroactively to tax years beginning on January 1, 1975. 33 U.S.T. at 2848.

The notice of deficiency on which this case is based determined, among other things, that the Norwegian municipal, national, and special charges claimed by petitioners as creditable taxes on their Federal consolidated income tax returns for the years 1979 through 1982 were not creditable pursuant to section 901 but were,- instead, creditable only to the extent provided by the treaty between the United States and the Kingdom of Norway. The parties now agree that petitioners’ tax liability (or the amounts of foreign tax credit) for the years 1979 and 1980 would not be different, whether the treaty or sections 901 and 904 of the Code are applied.

OPINION

Section 901 allows domestic corporations to claim foreign tax credits against U.S. Federal income tax for “the amount of any income, war profits, and excess profits taxes paid or accrued during the taxable year to any foreign country”. Sec. 901(b)(1). Section 903 provides that the term “income, war profits, and excess profits taxes” shall include a tax paid “in lieu” of a tax on income, war profits, or excess profits, generally imposed by a foreign country. The sole issue for decision in this part of the present case is whether the three charges paid by petitioners to the Kingdom of Norway during the years 1981 and 1982; namely, the municipal, national, and special charges, qualify as “income, war profits, or excess profits” taxes, or taxes “in lieu” thereof, so that they are creditable pursuant to section 901 or 903.

The foreign tax credit provisions were enacted primarily to mitigate the heavy burden of double taxation for U.S. corporations operating abroad which were subject to taxation in both the United States and foreign countries. Burnet v. Chicago Portrait Co., 1285 U.S. 1, 9 (1932); F.W. Woolworth Co. v. Commissioner, 54 T.C. 1233, 1257 (1970). These provisions were originally designed to produce uniformity of tax burdens among U.S. taxpayers, irrespective of whether they were engaged in business abroad or in the United States. H. Rept. 1337, 83d Cong., 2d Sess. 76 (1954). A secondary objective of the foreign tax credit provisions was to encourage, or at least not to discourage, American foreign trade. H. Rept. 767, 65th Cong., 2d Sess. (1918), 1939-1 C.B. (Part 2) 86, 93; Commissioner v. American Metal Co., 221 F.2d 134, 136 (2d Cir. 1955), affg. 19 T.C. 879 (1953).

Taxes imposed by the government of any foreign country were initially fully deductible in computing net taxable income, pursuant to our income tax law of 1913. Revenue Act of 1913, ch. 16, 38 Stat. 114. Specific foreign taxes became creditable pursuant to the Revenue Act of 1918. The foreign taxes that are presently creditable pursuant to section 901, specifically, income, war profits, and excess profits taxes, have remained unchanged and are the same taxes that were creditable in 1918. Revenue Act of 1918, ch. 18, sec. 222(a)(1), 40 Stat. 1073.

The definition of income, war profits, and excess profits taxes has evolved case by case. The temporary and final regulations, adopted relatively recently, outline the guiding principles established by prior case law. The temporary regulations were effective for taxable years ending after June 15, 1979. Sec. 4.901-2, Temporary Income Tax Regs., 45 Fed. Reg. 75648 (Nov. 17, 1980). Final regulations became generally effective for tax years beginning after November 14, 1983; however, taxpayers could elect to apply the final regulations to earlier open years. Sec 1.901-2(h), Income Tax Regs. Petitioners herein did not elect to apply these final regulations to taxable years beginning on or before November 14, 1983, with respect to the above-mentioned Norwegian charges; therefore, petitioners are subject to the temporary regulations with respect to these charges.

Petitioners argue that although they did not elect to apply the final regulations to the Norwegian charges imposed on Phillips Norway for 1981 and 1982, such regulations should be considered when interpretative issues arise, as the final regulations contain further explanatory, amplifying, and clarifying material and statements that would provide assistance to the resolution of the issue herein. We agree with respondent that petitioners are bound by their decision not to affirmatively elect application of the final regulations with regard to the Norwegian charges for the years in issue and must accept the burdens along with the benefits that flow from that decision. Helvering v. Wilshire Oil Co., 308 U.S. 90, 98 (1939); Georgia-Pac. Corp. v. Commissioner, 63 T.C. 790, 802 (1975); Valdes v. Commissioner, 60 T.C. 910, 912-914 (1973). Additionally, temporary regulations are entitled to the same weight as final regulations with respect to the years to which they apply. Nissho Iwai American Corp. v. Commissioner, 89 T.C. 765, 776 (1987).

The foreign tax must be the substantial equivalent of an income tax⁷ as that term is understood in the United States for section 901 to apply. New York & Honduras Rosario Mining Co. v. Commissioner, 168 F.2d 745, 747 (2d Cir. 1948), revg. and remanding 8 T.C. 1232 (1947). The meaning of the phrase “income taxes” is to be found in our own revenue laws, not in the taxing statutes or decisions of foreign jurisdictions. Biddle v. Commissioner, 302 U.S. 573, 578-579 (1938). Whether a charge imposed by a foreign country is an income tax must also be determined independently for each separate charge. Each separate charge will be considered either to be an income tax or not to be an income tax, in its entirety, for all persons subject to the charge. Whether separate charges are imposed by a foreign country depends upon the structure of the foreign law. Charges are separate when they are separately computed with respect to separate bases or separate rates, or if foreign law contains particular industry provisions. Sec. 4.901-2(a)(l), (d), Temporary Income Tax Regs.

Respondent argues that the municipal and national charges imposed on petroleum producers and pipeline transporters by the GTA, when modified by the special rules of the PTA, are not the “same” as the charges that would be imposed by the rules of the GTA alone; consequently, these modifications create in substance and effect significantly different charges that qualify as separate charges. Petitioners do not seem to disagree. We agree with respondent that when the special rules of the PTA are applied to alter the rules of the GTA, they modify the municipal and national bases of charge, thereby creating different taxable bases of charge. We find that the municipal and national charges as modified by the pta are separate from the same charges imposed by the GTA, even though the rates applied to each charge remained the same. As discussed further below, however, we do not agree that these modified charges are significantly different from those imposed by the GTA. There is no disagreement over whether the special charge is a charge separate from the municipal and national charges. Each of these charges, therefore, must independently meet the tests of creditability under section 901.

A foreign charge must satisfy three tests to qualify as a creditable income tax. A foreign charge: (1) Must not be compensation for a specific economic benefit; (2) must be based on realized net income; and (3) must follow reasonable rules regarding source of income, residence, or other bases for taxing jurisdiction. Sec. 4.901 — 2(a)( l)(i) — (iii), Temporary Income Tax Regs. The parties agree that the three Norwegian charges here follow the criteria of item (3) above. As to the first two tests:

1. Compensation for a Specific Economic Benefit

A foreign charge that is imposed only on persons that do not receive any specific economic benefit from a foreign country is not compensation for a specific economic benefit. Sec. 4.901 — 2(b)(1), Temporary Income Tax Regs. An economic benefit includes the right to use, acquire, or extract resources that a foreign country owns or controls. The term does not include the right or privilege merely to engage in business generally. A person upon which a charge is imposed receives a specific economic benefit if, and only if, the person receives an economic benefit that, in general, is not being received by persons upon which the charge is not being imposed. Sec. 4.901-2(b)(3), Temporary Income Tax Regs. The parties agree that those subject to the special charge under the Norwegian PTA were receiving a specific economic benefit, namely, the right to exploit Norwegian petroleum reserves on the Norwegian Continental Shelf. The more refined question, however, is: were they receiving such benefits as taxpayers, or as holders of exploitation licenses, for which separate fees were paid?

A foreign charge imposed on persons that receive a specific economic benefit from a foreign country is presumed to be compensation for a specific economic benefit. This presumption can be rebutted only if: (1) The same charge is also imposed on income of persons that do not receive any specific economic benefit from the foreign country; or (2) the amount of the charge paid by persons that receive the specific economic benefit is not significantly increased over what this amount would be if such persons were, instead, subject to an income tax imposed by the foreign country only on income of persons that do not receive the specific economic benefit; or (3) it is demonstrated that no significant part of the charge is compensation for the specific economic benefit received. Sec. 4.901-2(b)(l) and (2), Temporary Income Tax Regs.

(a) Municipal and National Charges

Respondent contends that all three Norwegian charges are additional compensation for a specific economic benefit, that is, additional compensation for the right to exploit Norway’s petroleum reserves. Respondent thereby asserts that petitioners must rebut the compensation presumption for each of the three Norwegian charges by demonstrating that no significant part of each charge is compensation for the specific economic benefit received. Respondent reminds us that only those engaged in offshore petroleum exploitation and pipeline transportation activities, that is, petroleum exploitation and pipeline transport licensees, were subject to all three Norwegian charges as modified, or created by the PTA. Consequently, respondent argues that the tax bases and the amount of the charges imposed pursuant to the PTA substantially exceeded the tax bases and the amount of the charges imposed pursuant to the GTA; therefore, enactment of the PTA significantly increased the revenues or compensation received by Norway from petroleum producers for all three Norwegian charges. Ultimately, it is respondent’s position that Norway enacted the PTA to increase the compensation it received for each Norwegian charge; therefore, each charge is an additional royalty paid to Norway as compensation for the use of its petroleum reserves. Respondent also advances the position that the PTA provision limiting the deduction for onshore deficits to only 50 percent when applied against offshore income resulted in a significant increase in the taxes imposed by the PTA.

Petitioners point out that both before and after enactment of the PTA, petroleum companies continued to remain liable for Norwegian municipal and national charges, admittedly modified, in addition to substantial royalty obligations. Petitioners argue that the industry-specific rules enacted by the PTA, which superseded or supplemented the GTA rules, did not transform preexisting taxes, namely, Norway’s municipal and national charges, into royalties.

We agree with petitioners’ assertion that respondent’s argument that all three Norwegian charges are disguised royalties would require us to hold that Norway, by enacting the PTA, chose to exempt petroleum producers and pipeline transporters from all Norwegian income taxes and to impose additional royalties in place thereof. Respondent contends that petitioners must compare the income tax paid by non-petroleum-producing taxpayers to that of petroleum-producing taxpayers in order to carry their burden of demonstrating that the amount of the municipal and national charges paid pursuant to the PTA are not significantly greater than those charges paid pursuant to the GTA rules. We disagree with the last contention.

Upon exhaustive examination of the GTA, the PTA, other Norwegian general tax legislation, legislative history, the testimony from two Norwegian tax experts⁸ (and their reports), we find that the PTA did not significantly increase the charges due from petroleum producers or pipeline transporters, in the case of Norway’s municipal and national charges. In fact, due to the additional uplift allowance, the overall liability for these two charges, in all likelihood, was reduced by the modifying provisions of the PTA. We also do not find the 50-percent limitation against offsetting onshore losses with shelf district income to significantly increase the municipal or national charges. As much as 50 percent of onshore losses was deductible in the year of loss against offshore income for the municipal and national bases of charge. The remaining 50 percent could be carried over and utilized for a period of 10 years as onshore districts generated income. This limitation does not deny the deductibility of 50 percent of onshore losses. This provision merely creates the potential for deferral.

We hold that the rules of the PTA when applied to modify the municipal and national charges do not significantly increase petitioners’ liability regarding these charges, but merely add industry-specific tax rules in order to advance Norway’s tax policies with regard to the petroleum industry. Petitioners rebutted the presumption that these charges (municipal and national) are compensation for a specific economic benefit. Both Norway’s municipal and national charges as applied to petitioners are taxes in the U.S. sense; neither are royalties paid for the use of Norway’s petroleum reserves; therefore, neither are additional compensation for a specific economic benefit.

(b) Special Charge

Unlike the Norwegian municipal and national taxes, only petroleum producers and pipeline transporters were liable for the Norwegian special charge. As this charge was specifically targeted at the petroleum industry and was not generally imposed on the Norwegian populace, we agree that petitioners cannot rebut the “compensation” presumption for the special charge with either the “same charge” or “significant increase” provisions, but must demonstrate that no significant part of the special charge was compensation to the Norwegian Government for a specific economic benefit received.

Initially, we must clarify the specific economic benefit received by petitioners and the compensation paid to Norway. Petitioners specifically received the exclusive right to explore for and exploit Norwegian petroleum deposits in the areas awarded by their license grant. The compensation paid to Norway was in the form of a one-time area fee, annual area fees, and an annual 10-percent royalty interest; that is, a 10-percent share of the quantity of petroleum extracted at the wellhead and saved by petitioners during the year. Petitioners were also required to complete a 6-year work program that included the drilling of five wells within their license area.

Respondent asserts that Phillips Norway as well as other licensees, through their licensing concessions, acquired the right to extract and exploit Norwegian petroleum, and that licensees retained the right to continue production and received additional rights due to enactment of the PTA, specifically, the right to receive future valuable North Sea licenses.

Respondent’s argument finds no support in the facts. We agree with petitioners that petroleum licensees were not granted additional rights, benefits were not increased, and the costs of obtaining benefits were not reduced with respect to petroleum production by the enactment of the PTA or through the payment of special charges. Petitioners specifically did not receive additional rights of exploration or exploitation. Potential petroleum producers could seek additional license grants to explore for and exploit Norwegian petroleum resources, but applicants would receive such rights only upon the approval of the Ministry of Petroleum and only after that Ministry reviewed applicant filings, including information regarding an applicant’s experience in petroleum exploration and exploitation, and an applicant’s financing capabilities. Applicants were never assured of success. Further, petroleum licensees retained their right to continue or extend their granted term of exploitation only upon the successful completion of work programs, other grant conditions, and through the payment of fees, including royalty payments.

Respondent argues that the failure to pay Norwegian charges could result in license forfeiture, and this fact indicates that the payment of such charges was actually compensation to the Norwegian Government, paid in the form of a tax for the right to exploit Norway’s petroleum reserves. We disagree. The remedy of license revocation was specifically delegated to the Ministry of Petroleum as provided in the petroleum regulations administering the conduct of petroleum operations on the Norwegian Continental Shelf. Such remedy was limited to the untimely payment of fees* royalties, and other payments required of a license grantee qua licensee, not taxpayer. The petroleum regulations did not provide for license revocation upon the nonpayment of Norwegian taxes. The Ministry of Petroleum had no authority to enforce collection for the nonpayment of Norwegian taxes; such authority rested with the Ministry of Finance. Petitioners contend that the failure to pay the special charge would not cause the revocation of the petroleum license. Although there are no specific provisions in the GTA or PTA providing the remedy of license revocation for the nonpayment of Norwegian taxes, such remedy could be the indirect result of bankruptcy. Such an indirect remedy does not sway us to find that Norway was actually receiving additional compensation in the form of special charge payments under the PTA for its grant of petroleum exploitation rights. New York & Honduras Rosario Mining Co. v. Commissioner, 168 F.2d at 748.

Both parties recognize that to accomplish its purpose, Norway had to impose a charge in the form of a tax. Each party takes a slightly different slant on what that purpose was. Respondent contends that Norway’s purpose in enacting the PTA was to claim additional compensation for the use of its resources. As evidence of Norway’s compensation goal, respondent argues that Norway owned its petroleum reserves, actively controlled the exploitation and extraction of such petroleum from the Norwegian Continental Shelf, and enacted the PTA believing that a prescribed level of petroleum profits rightfully belonged to the Norwegian people. For further support, respondent notes that Norway periodically changed its “tax” rate as the market outlook and profitability of the petroleum industry fluctuated, and argues that Norway increased or decreased the rates of special charge in order to obtain a desired level of compensation for the use of its petroleum reserves. Respondent points to PTA amendments of 1980, specifically the rate increase from 25 to 35 percent and the reduction in the uplift allowance, as actual evidence of Norway’s changing compensation goal.

Petitioners argue that in purpose, design, and effect, Norway enacted the PTA and imposed a tax, not to claim additional compensation for the right to extract petroleum resources, but to claim a larger share of petroleum profits, by taxation, from an industry that in its estimation would otherwise receive “windfall” or “excess” profits, due to surging oil prices that created an entirely new profit situation. Petitioners argue that this motive was not unlike that which precipitated the enactment of the Crude Oil Windfall Profits Tax Act in 1980 by the U.S. Government. Pub. L. 96-223, 94 Stat. 229. Respondent is correct when arguing that the U.S. windfall profit tax is not comparable to Norway’s special charge, as it was a temporary excise tax designed to encourage increased domestic oil production and to finance alternative energy programs. H. Rept. 96-304, at 7-8 (1979), 1980-3 C.B. 81, 91-92; sec. 4988(b)(3)(B) (as it read in 1980).

Respondent’s allegation that Norway sought a desired or prescribed level of compensation through enactment of the PTA was drawn from comments made by a group in committee recommendations before the Storting preceding enactment of the PTA. As this group was apparently a minority party, we do not find such comments reflective of the majority’s general comments. Based on Norwegian legislative history, we have found that Norway’s purpose behind the enactment of the PTA was in fact 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.

Norway’s purpose for enacting the PTA reveals only part of the picture. To answer the compensation question, we feel we must also attempt to examine the amount of compensation actually paid to Norway, in the form of royalties and otherwise. Assuming for a moment that the norm price determinations made by the PPB for 1981 and 1982 reflect fair market values, we find that when norm prices are averaged over each year and applied to the quantities of crude oil paid by petitioners in kind as royalties during these periods, the result is that Norway received oil taken in kind, worth nearly $168 million in 1981, and over $126 million in 1982, as compensation in the form of a share of production. Norway also received approximately $30 million in 1981, and $23 million in 1982, from natural gas and NGL royalties, as well as natural gas royalties taken in kind, of an undetermined value. Given the relationship between Norwegian kroner and U.S. dollars during 1981 and 1982, it appears that the Norwegian krone equated to approximately 17.5 and 15.6 cents in U.S. dollars, respectively. Also, given that Phillips Norway paid approximately NKr2,711,945,310 and NKr2,873,609,166 in special charges, respectively, during 1981 and 1982, we find that Phillips Norway paid Norway approximately $474,590,429 and $448,283,030 in special charges, respectively, during 1981 and 1982.

Petitioners remind us that the same fees and royalties that had compensated Norway for its petroleum resources before enactment of the PTA continued to be collected by the Norwegian Government following enactment of the PTA; therefore, petitioners argue that Norway was already adequately compensated for the right to exploit its minerals, and petitioners paid for and maintained that right through the payment of royalties and fees; consequently, special charges payments could not be additional “compensation” for such right.

Examination of the amount of compensation in this case is not determinative. We note that Norway received special charges in amounts approximating two to three times the value it received in royalties and other fees. We find the sums paid to Norway, in the form of royalties and other fees exchanged for the rights granted to exploit its resources, to be substantial; therefore, we do not question the adequacy of such compensation paid to Norway.

Respondent recognizes that an increase in compensation or revenues to a government is not necessarily accompanied by additional rights when the government as owner can unilaterally change its compensation agreement; therefore, in the alternative, respondent ultimately contends that Norway enacted the PTA and imposed the special charge on petroleum licensees in order to extract additional compensation for the use of its resources, and this compensation, although exacted in the form of a tax, is in fact a royalty or an excise tax, not an income tax.

Respondent states correctly that payments made to an owner of minerals, by an operator, of a portion of the proceeds from oil production measured by the net profits of the operation can be a royalty. Kasey v. Commissioner, 33 T.C. 656 (1960). Respondent contends that a charge calculated as a share of the net financial income attributable to petroleum production is more in the nature of a rent or royalty than a tax on income, as income flows directly from the economic interest in the mineral. We recognize that the Supreme Court has determined that when an owner/lessor leases a mineral property to an operator/lessee and that owner, as lessor, has retained a royalty interest based on the net profits of this single operation, such lessor has retained an economic interest in that mineral property, sufficient to claim depletion deductions. Such net profits payments are more in the nature of rent than an outright sale as they flow directly from the owner’s mineral property. Kirby Petroleum Co. v. Commissioner, 326 U.S. 599, 606-607 (1946). The Supreme Court, however, did not determine whether the profit from such a retained interest was a royalty or a tax. That issue was not presented to the Court. The Supreme Court simply determined that the taxpayer had retained a sufficient economic interest in the mineral property through his retained royalty interest to allow him to claim depletion deductions. The fact that the interest retained was a royalty was posited. These two cases, along with many others, have focused on the characterization of the relationship between the owner of minerals and the operator; however, such focus has never addressed the issue before us.

Without question Norway has an economic interest in the mineral resources which it granted licenses to exploit. However, Norway is a sovereign nation. Our dilemma lies in the fact that the United States and Norway, as sovereign nations, wear two hats when they are also the owners of minerals. Each, as the owner of petroleum resources, is able to exact royalties, and each, as a sovereign, is able to impose taxes.

Our focus here is not to make the more difficult distinction between a royalty interest retained by a government and a government-imposed excise, privilege, or production tax when each is based on the net profits of an operation. Excise taxes are typically taxes laid upon the manufacture, sale, or consumption of commodities, upon licenses to pursue certain occupations, and upon corporate privileges enjoyed within a country. Flint v. Stone Tracy Co., 220 U.S. 107, 151 (1911). They do not qualify as “income” taxes because they are not the substantial equivalent of an “income tax” as that term is understood in this country, for they fail to effectively reach net profit. Bank of America Natl. Trust & Sav. Association v. United States, 198 Ct. Cl. 263, 459 F.2d 513 (1972); Bank of America Natl. Trust & Sav. Association v. Commissioner, 61 T.C. 752, 760-761 (1974), affd. without published opinion 538 F.2d 334 (9th Cir. 1976). Excise taxes are typically imposed on gross revenues, the value of output, or on an uncustomary “net” profits calculation that is restricted to particularized expenses, generally the direct operating costs of mineral operations, and nothing more. Keasbey & Mattison Co. v. Rothensies, 133 F.2d 894 (3d Cir. 1943).

Our focus here is to distinguish between a royalty interest retained by a government, as the owner of natural resources, and a tax imposed on the net profits generated predominantly from the same government-owned resources. The preliminary determination of whether a foreign levy is a “tax” is also decided under U.S. definitions of a “tax”. Texasgulf, Inc. v. United States, 17 Cl. Ct. 275, 285 (1989). The word “tax” in this country 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. Amtorg Trading Corp. v. Commissioner, 25 B.T.A. 327, 332-333 (1932), revd. on another issue 65 F.2d 583 (2d Cir. 1933). 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. Cox v. Commissioner, 41 T.C. 161, 164 (1963). A royalty refers to a share of the product or profit reserved by an owner for permitting another to use a property. Sneed v. Commissioner, 33 B.T.A. 478, 482 (1935).

All taxes, levies, duties, tolls, tariffs, imposts, and other charges, imposed by any level of government, raise revenues that add to the public purse. All retained royalty interests do the same. We find the reasons for which Norway chose to enact another layer of tax, as the method for augmenting its treasury, irrelevant to the determination of whether Norway imposed a tax or a royalty. This Court has stated that the test of creditability rests not upon the power to tax but upon the manner in which that power is exercised. Bank of Amer-ica Natl. Trust & Sav. Association v. Commissioner, supra. We must examine the nature and effect of the charge, specifically the manner in which each charge was proposed, drafted, structured, and administered. Flint v. Stone Tracy Co., supra.

When the owner of a mineral interest is a government, the distinction between a royalty interest and a tax can only be determined by an examination of the particularities involved in the imposition of the charges. While labels should not be determinative in the question of creditability, the declaration of the lawmaking power is entitled to much weight. Flint v. Stone Tracy Co., supra. We cannot close our eyes to the fact that the legislation Norway enacted was entitled the PTA. Norway imposed the special charge pursuant to the exercise of its sovereign taxing power, not pursuant to its proprietary rights, as an owner of petroleum resources. The Ministry responsible for tax legislation, the Ministry of Finance, held committee meetings to discuss proposals for the new tax and provided recommendations to the Norwegian Parliament. Each Norwegian expert in this case agreed that Norway’s undeniable purpose was to impose a tax. We agree also.

Respondent argues that it is irrelevant that petroleum charges and royalties were administered separately, as such separate administration is not part of the test. Respondent is mistaken; we have found that separate administration is a fact relevant to creditability determinations. American Metal Co. v. Commissioner, 19 T.C. 879, 883 (1953), affd. 221 F.2d 134 (2d Cir. 1955). The facts reveal that the administration of license grants and the collection of royalties were delegated to the Ministry of Petroleum, while the administration of all taxes, including the special charge, were delegated to the Ministry of Finance. Each Ministry was independent of the other.

A typical royalty interest does not give effect to items of income or expense, and a royalty interest based on net profits typically does not allow for the deduction of nonproduction expenses. Norway was assured a share of production regardless of the profitability, or lack thereof, experienced by a licensee. The PTA did not attempt to tax separately the net profit (if any) generated by each individual field exploited. Instead, the special tax was calculated on net profits of a taxpayer’s entire gas and petroleum operation. Unlike a royalty interest, the base for the special charge was determined not as a share of production, but rather was imposed on shelf district income, whether such profits were generated from production or nonproduction activities. Also, no matter how much production an operator achieved, special charges would not result, unless a taxpayer generated a net profit after account was taken of expenditures that were not restricted to the operating costs involved in extracting petroleum. Finally, unlike the royalty interest retained by Norway, special charge liabilities were not paid in barrels of petroleum produced, but in cash. The special charge was not inextricably interwoven with the grant to exploit Norwegian petroleum resources. Norway intended to impose a tax, did in fact impose a tax, structured the charge as a tax, and administered it accordingly. If it quacks like a duck and waddles like a duck, it’s a duck, unless of course, we determine that it’s a decoy, which we do not find.

Admittedly, Norway has not found the petroleum industry’s excess profits situation to be temporary, but has determined that the petroleum companies, exploiting Norwegian resources in the Norwegian Continental Shelf, inherently earn profits beyond what in Norway’s estimation are reasonable. It is not our prerogative to dispute Norway’s wisdom.

Petitioners rebutted the compensation presumption by demonstrating that no significant part of the special charge was compensation for a particular economic benefit received. The special charge is a tax in the U.S. sense and is not a royalty or compensation paid for the right to exploit Norway’s petroleum reserves.

2. Realized Net Income

A foreign charge is computed on the basis of realized net income if, and only if, it meets the realization, net income, and gross receipts tests. Sec. 4.901-2(c), Temporary Income Tax Regs. Respondent agrees that petitioners have met the realization test, as the events that result in the realization of income pursuant to the norm price system are the transfer or processing of a readily marketable property (petroleum), and such realization occurred prior to, or corresponded with, the realization of income under the income tax provisions of the Internal Revenue Code. Sec. 4.901-2(c)(2), Temporary Income Tax Regs. As to the two other requirements:

(a) Gross Receipts

A foreign charge meets the gross receipts test if it is imposed, without substantial deviation, on the basis of: (i) Actual gross receipts, or alternatively (ii) gross receipts computed under a method that is designed to produce an amount that is not greater than fair market value and that, in fact, produces an amount that approximates, or is less than, fair market value, but only in the case of: (A) Transactions with respect to which it is reasonable to believe that gross receipts may not otherwise be clearly reflected or (B) situations involving the transfer or processing of a readily marketable property, wherein realization events occur prior to realization pursuant to the Internal Revenue Code. Sec. 4.901 — 2(c)(3), Temporary Income Tax Regs. Due to the fact that crude oil is a readily marketable property, respondent agrees that should petitioners meet all other requirements, an alternative method of calculating gross receipts could be acceptable. There is also support for the position that an alternate gross receipts method may be acceptable under (A) above, as Norwegian authorities reasonably believed that gross receipts would not otherwise be clearly reflected, where petroleum sales were occurring between affiliated companies in transactions that were not subject to ordinary market forces.

Due to the Norwegian norm price system, we agree that petitioners must meet the alternative gross receipts requirements in order to pass the gross receipts test. Respondent argues that because norm price determinations applied in calculating all three Norwegian taxes for petroleum producers subject to the PTA, none of these Norwegian taxes pass the gross receipts test, as the norm price system was not designed to produce an amount not greater than fair market value, and such a system did not, in fact, produce an amount that approximated, or was less than, fair market value. We consider these dual arguments separately:

(i) Gross Receipts Method Designed To Produce an Amount Not Greater Than Fair Market Value

Norwegian authorities examined the situation Norway was faced with regarding the very large, resourceful, international, and fully integrated petroleum companies operating in its shelf district, which were predominantly transferring Norwegian-produced crude oil among related affiliated companies. Pursuant to this examination, Norwegian authorities determined that due to Norway’s size, limited resources, and the complexities involved in determining real transfer prices for each crude oil sale, Norway would bypass such costly and complicated taxpayer-by-taxpayer determinations, with the establishment of the norm price system. The purpose of the norm price system was to achieve prices that reflected ordinary market forces, in situations where it was determined that ordinary market forces were absent from actual transaction evidence. This determination was made for crude oil alone, and was not broadly applied to all petroleum products, or to other industries. We do not find fault with Norway’s answer to a complex and costly problem. The actual process of determining norm prices was both participatory and adversarial, and taxpayers themselves were an integral part of the process. Such a system essentially put taxpayers to their proof before taxes were assessed. When respondent contends that Norway established the norm price system as an essential component in its plan not only to control the petroleum industry but to artificially increase revenues and tax receipts, by retroactively determining the share of offshore profits it desired, respondent insinuates an ulterior motive on the part of Norwegian authorities that we are not prepared to find.

Upon review of this record, we have no doubt that Norway designed its norm price system to produce gross receipt prices that approximated fair market value. The norm price regulations issued by the King mandated that each norm price would be equivalent to the price at which petroleum could have been sold between independent parties in a free market. Contrary to respondent’s assertions, the guidelines that delineated the specific factors that the PPB was to consider in its pricing determinations did not effectively modify the stated mandate by requiring the consideration of non-arm’s-length data, such as parity, quoted, and official selling prices. Such guidelines accorded direction, but did not limit the PPB in its review of data. These guidelines provided that, in addition to the factors and data delineated, the PPB was required to consider any other comparable prices, and any circumstances that could affect price. Also, contrary to respondent’s suggestion, the norm price guidelines required the PPB to consider realized prices. Respondent argues that the norm price guidelines allowed the consideration of nonmarket factors. We disagree. Inherent in the mandate and guidelines is the principle that the evidence upon which a norm price would finally be based would be limited to relevant market evidence.

Respondent also has difficulty with the fact that the Petroleum Ministry regulating petroleum operations was also delegated responsibility for norm price determinations. We find such delegation of power might be questionable only if the Ministry in charge of tax administration, the Ministry of Finance, had authority to set such prices, thereby setting the resulting revenues upon which tax liabilities would be determined.

Respondent argues that the norm price method is an unacceptable gross receipts method as the resulting gross receipts are unrelated to an individual taxpayer’s actual gross receipts, do not reflect fair market value at the time of delivery or sale, and are determined by one set figure presumably reflective of an entire quarter. Although example 19 of section 4.901-2(e), Temporary Income Tax Regs., exhibits these characteristics, respondent believes such example to be distinguishable from the case herein.

We note that the product herein is a readily marketable commodity, and as norm prices were determined for specific geographic production areas, such a uniform price can reflect fair market value over a period of time, when the market is retroactively examined. Example 19 specifies the standard for accepting such a uniform price, as the weighted average of reported prices for arm’s-length sales in the country in question, and comparable petroleum sales from other countries, pursuant to long- and short-term contracts and the spot market. Respondent makes much of the weighted average language in example 19, alleging that an actual mechanical averaged weighting of prices is necessary. We do not agree that any fair market value determination can be structured into a predetermined formula with varying standardized weights and specified relevant factors. The relevancy of market evidence cannot be standardized or weighted, in a complex and ever-changing market such as the market for petroleum. Such a restriction in the determination of fair market values would be detrimental to a true fair market valuation. We find that such language was not meant to have such a restrictive meaning, but was meant to be expansive, to recognize constantly changing market circumstances.

Norwegian norm price determinations were, appropriately, not based on predetermined formulas, but were the result of considered decisions by each PPB member, based on all relevant evidence before the PPB, including submissions and arguments presented by taxpayers themselves. The norm price guidelines were such that the PPB was given wide latitude in determining the weight to apply to relevant data, and, as respondent suggests, the PPB, in its discretion, could disregard actual third party sales should the PPB, in its judgment, determine that such prices were not reflective of the market.

We do not feel that there is any meaningful distinction to be found between the standard espoused in example 19 and the mandate and guidelines provided in the Norwegian norm price regulations; both are obviously attempting to achieve fair market values. In fact, in the absence of other information, we might be hard pressed not to find that Norway designed the norm price system to mirror the elements of example 19. A taxpayer has the right to rely upon Government regulations and their published illustrations. As stated earlier, temporary regulations are entitled to the same weight as final regulations with respect to the years to which they apply. Nissho Iwai American Corp. v. Commissioner, 89 T.C. at 776. It has been long held that regulations, to the extent not inconsistent with the statute, have the force and effect of law. The suggestion that regulations are binding on taxpayers but not on the Commissioner cannot be entertained. Pacific Natl. Bank v. Commissioner, 91 F.2d 103, 105 (9th Cir. 1937), revg. 34 B.T.A. 8 (1936). Contrary to respondent’s arguments, the stated objective and the corresponding norm price guidelines do, in and of themselves, determine whether a gross receipts method was designed to approximate fair market value. Respondent’s difficulty with the fact that PPB conclusions cannot be verified, as they are confidential and not publicized, should more appropriately be addressed to the question of whether such method actually operated, in fact, to approximate fair market values. We find that the norm price method used here was designed to produce an amount not in excess of fair market value.

(ii) Gross Receipts Method That in Fact Approximates, or Is Less Than, Fair Market Value

Gross receipts must be computed under a method that in fact approximates, or is less than, fair market value. Sec. 4.901-2(c)(3)(ii), Temporary Income Tax Regs. Fair market value represents the price at which property would change hands between a willing buyer and seller, neither being under a compulsion to buy or sell and both having reasonable knowledge of relevant facts. United States v. Cartwright, 411 U.S. 546, 551 (1973). The question of fair market value is one of fact, for which the trier of fact has the duty to weigh all relevant evidence and draw appropriate inferences. Hamm v. Commissioner, 325 F.2d 934, 938 (8th Cir. 1963), affg. T.C. Memo. 1961-347.

In the case at bar, we received testimony and expert reports from three expert witnesses: petitioners put forth two experts, Keith Hamm (Hamm) and John H. Lichtblau (Lichtblau), and respondent one expert, Peter R. Odell (Odell). We are not bound by the opinion of any expert and will accept or reject expert testimony in the exercise of sound judgment. Estate of Hall v. Commissioner, 92 T.C. 312, 338 (1989). We may find one expert more persuasive or helpful on one element of valuation and another more persuasive or helpful on another element. Parker v. Commissioner, 86 T.C. 547, 562 (1986).

All three experts agree that prior to the years in question, 1981 and 1982, the price of oil experienced two unprecedented price spikes or shocks as well as unprecedented levels of volatility. During the years in issue, the market began to stabilize somewhat as it experienced reduced levels of price volatility; however, the trend was an overall decline in prices. Many market players incorrectly anticipated a continuation of the rising trend in oil prices. Short-term price movements through the years in issue remained relatively volatile although to a lesser degree. Six principal shifts, downward and upward, occurred over this 2-year period.

In 1981 and 1982, arm’s-length petroleum transactions were conducted either through term contract arrangements or as single spot transactions. Term contracts provided the benefits of supply reliability and pricing stability. Term prices were commonly fixed for a period of time and typically adjusted quarterly or monthly as market conditions dictated. Spot prices indicated the price of a single transaction such as for one cargo of crude oil. Spot prices reflected present market conditions but did not account for longer term factors in the industry. Therefore, the prices associated with term arrangements and spot transactions behaved differently. Term arrangements did not respond immediately to daily changes in market conditions; consequently, term price changes were less volatile than spot market price movements. However, over time term pricing could prove advantageous. Spot prices lead the market and its direction. The term market generally lagged behind spot trends but followed the direction of the spot market. Each expert recognizes, and the evidence shows, that norm prices tracked term price fluctuations.

Today, crude oil has become just another commodity and a small number of key spot-traded crude oil prices determine almost all other crude oil prices in the international market. In 1983, crude oil futures contracts began trading on the New York Mercantile Exchange. Unlike today’s sophisticated markets, during the years in issue instantaneous pricing information was not readily available. Reporting of spot transactions was in its infancy, and the number of available publications were few. Industry journal pricing information was developed through informal discussions between reporters and market participants. Reporters were responsible for distilling imperfect information into a publication’s best judgment of the “correct” price on any given day. This information can now be electronically cross-checked for accuracy. All experts recognize that while the data published by industry trade journals may be imperfect, such publications were relied on by the industry as a whole.

Each expert relied on several market factors and presented the issue of value in a different manner. The appendix attached illustrates the various useful positions advocated by each expert.

Hamm, managing director of Petroleum Economics Ltd. (pel), joined PEL in 1969. In 1954, PEL was established as an international oil consultancy firm in London, U.K. PEL specializes in economic and political aspects of the oil and gas industry, assesses the petroleum market on an ongoing basis, and maintains a series of data bases derived from published and private information sources, including industry and client contacts. For the years in issue, PEL supplied the PPB with information on market developments, oil prices, and analyses of other data. PEL gave no opinions regarding the setting of norm prices and did not receive prior notification of pricing decisions.

Hamm’s analysis indicated that term arrangements dominated arm’s-length trade during 1981 and 1982; consequently, he relied solely on term prices as indicators of fair market value. Columns (1) and (n) of the appendix, respectively, illustrate term prices for Ekofisk crude oil as reflected in pel databases and selling prices offered by the British National Oil Corp. (bnoc) for Forties crude oil. Forties is a crude oil blend produced as a major production stream from the U.K. sector of the North Sea and landed by pipeline in Scotland. BNOC handled over half of the North Sea’s production volumes. BNOC was set up by the British Government as a state company that held a 51-percent participatory equity interest in all U.K. North Sea oil fields, bnoc received most of its oil supply from participation, royalty, and equity agreements. Excluding volumes involved in buyback arrangements of participation oil, BNOC sold approximately 70 percent of the oil it acquired through term contract arrangements. Over 80 percent of these transactions involved five major international petroleum companies. BNOC allegedly paid market price for each barrel of production it lifted.

Hamm relied on Ekofisk term prices as the single best value indicator for Ekofisk crude oil. Hamm stated that pel derived these Ekofisk term prices from published assessments of contract term prices for all sellers of Norwegian crude oil, including Phillips Group and Statoil (a Norwegian-owned oil producer). Hamm compared these value indicators with norm prices and determined that norm prices were in fact in line with term price indicators. Hamm relied on BNOC’s announced prices for Forties crude oil as corroborative evidence supporting his Ekofisk term prices. Due to the recognized quality of Ekofisk as a lighter gravity crude oil, the market generally exhibited a recognized 75-cent differential between the price of Forties and Ekofisk crude oils.

Respondent argues that price changes in Ekofisk term contracts were made solely to bring Ekofisk prices into line with BNOC official selling prices and, consequently, these prices were not reflective of free market transactions. Recognizing the existence of a quality differential of 75 cents between these two crude oil types, it is clear that of the numerous trend lines developed by Odell, Norwegian norm prices closely and uncharacteristically tracked only BNOC prices for Forties crude oil. Also, whenever the BNOC changed its official selling prices (osp’s), Statoil changed its announced price for Ekofisk crude to an amount that was generally 75 cents greater than the BNOC price. OSP’s are prices set by producing companies that represent the price at which the company, in this case a state company, was willing to sell a barrel of oil.

Hamm was not surprised that his Ekofisk term prices tracked Statoil’s announced prices for Ekofisk crude oil. Given the above relationships, it becomes probable that BNOC Forties term prices also generally tracked Statoil’s announced term prices. We are concerned with respondent that this may be a case of the tail wagging the dog and that Hamm’s Ekofisk term prices were actually announced or official selling prices rather than market prices.

Lichtblau is now and has been the chairman of Petroleum Industry Research Associates, Inc. (pira), an international petroleum research and consultancy firm, since it was established in 1976. For the first 4 years of his career, Lichtblau worked as an economist for the U.S. Department of Labor and consulting firms until he became associated with Petroleum Industry Research Foundation, Inc., in 1956. During his career, he received the International Association for Energy Economics Award for Outstanding Contribution to the Profession of Petroleum Economics.

Lichtblau prepared revised actual third-party sales data reported by the Phillips Group as reflected in column (d) of the appendix. He additionally relied on spot transaction evidence reported by the Energy Economic Review (eer), an industry trade journal, as reflected in column (j), and Department of Energy (doe) data that we have chosen not to include in the appendix. Lichtblau relied on two trade journals that publicized spot prices. As the incomplete data set was very similar to that of the completed EER data set, we included the EER data set in the appendix, as this data is more useful to our determination. Although Lichtblau ranked DOE data second in importance when resolving the valuation issue herein, we question the usefulness of data that involves a multitude of unexplained assumptions. A special adviser to pira calculated the DOE values; however, he did not testify, and Lichtblau was not able to explain these values to our satisfaction. Additionally, the DOE data included interaffiliate transactions, and a questionable method was utilized in an attempt to remove these sales from the data base.

Lichtblau did not include volume-weighted average values in his report but rather defined fair market value as the range of his developed value indicators including Phillips Group sales, DOE data, and published spot prices. Lichtblau determined that Norwegian norm prices approximated fair market value by illustrating that such prices fell within a price range that spanned the single high and the single low of his transaction prices. We do not find Lichtblau’s very broad price band to be particularly helpful here.

Odell’s background is impressive, and his accomplishments are numerous. Subsequent to receiving his Ph.D. in 1954 and after service with the Royal Air Force, Odell worked for Shell International Petroleum Co. as an economist. From 1961 until he retired in 1990, Odell was involved with academia at several learning institutions including the London School of Economics, the Netherlands School of Economics, which is part of the Erasmus University in Rotterdam, and the College of Europe in Bruges. He has served as editor of several trade publications and published several books and articles relating to the economics of oil and other energy sources for a wide range of academic, professional, and technical journals. Odell has advised governments, international organizations, and other institutions on questions of international energy and presented evidence before energy committees of the U.S. Senate and U.K. Houses of Parliament, the International Chamber of Commerce in Paris, and the International Court of Justice in The Hague.

Odell presented several value indicators but ultimately relied solely on spot market evidence as the best indication of value. He adds the value indicators in appendix columns (f) and (h). Odell primarily relied on Ekofisk spot prices in column (f). These prices represent 64 trades and were derived from the Petroleum Argus database, a reputable trade journal. The spot prices in column (h) represent 723 trades derived from a basket of 16 North Sea and African light crude oils including Amna, Bonny Light, Brass River, Brega, Brent, Ekofisk, Es Sider, Escravos, Forties, Ninian, Saharan Blend, Sarir, Sirtica, Thistle, Zarzaitine, and Zueitina. Odell included this basket of 16 crude oils to lend support for the correctness of his final Ekofisk value indicators in column (f). The Strategic Petroleum Reserve (spr), administered by the Department of Defense, purchases crude oil and stores emergency stockpiles for future needs in caverns in Louisiana and Texas. We have not included Odell’s parity values or his SPR contract indicators in the appendix, as we find the parity values require us to make far too many questionable assumptions, and we are not sufficiently comfortable with the SPR values in the same way we were not sufficiently comfortable with Lichtblau’s DOE or Hamm’s BNOC data. Critical buyer-seller relationships and potential strategic advantages were not sufficiently developed. Additionally, there is no evidence that the SPR purchased Ekofisk crude oil during the years in issue.

Hamm and Lichtblau each argue that spot transactions were extremely limited during 1981 and 1982, both in terms of the overall size of the market and the size to which this market ultimately grew. Hamm estimated the size of the spot market as approximating 2 and 4 percent of world oil production (excluding the Soviet Bloc but including internal transfers of oil), and 8 and 25 percent of total North Sea production (Norway and U.K.) during 1981 and 1982, respectively.

All experts agree that due to the integrated nature of the oil industry, the volume of internal transfers was significant. For 1981 and 1982, third-party arm’s-length sales accounted for merely 14 and 9 percent of the volumes of oil produced by Phillips Group members. No expert, however, provided cogent evidence illustrating the dominance, or lack thereof, of the term market. The only and also the best evidence revealing the percentages of crude oil transferred in nonaffiliated spot and term transactions during the years in issue are the actual volumes transferred through actual third-party sales transacted by the Phillips Group during this period. These volumes indicate that during 1981 and 1982, respectively, term contract arrangements accounted for 39 and 45 percent, and spot transactions accounted for 61 and 55 percent, of the arm’s-length third-party sales that Phillips Group transacted. When volumes are combined for both years, term and spot transactions, respectively, accounted for an overall 41 and 59 percent of Phillips Group’s third-party transactions. The significance of these percentages cannot be ignored.

Hamm predominantly relied on the term market. Odell concluded that the spot market was the best indicator in valuing Ekofisk crude oil. Odell testifies that the petroleum industry during this period was dominated by collusive influences such as the Organization of Petroleum Exporting Countries (OPEC) and administered and official selling prices, and that actors played to the rules established by producers; therefore, the market was not “freely” competitive. Odell asserts that the term market was not part of a “free” market in which prices arose instantly from the continuing interplay of the forces of supply and demand. We disagree. Although the structure of the petroleum market was changing during the years in issue, term contracts continued to exist and continued to benefit the parties in terms of supply security and price stability. Additionally, buyers and sellers often are unable to control the market in which they must compete, and although the market herein may not have been as “free” as Odell would like, we cannot overlook that significant volumes of oil were transacted during the years in issue through spot as well as through term arrangements. We find that reliance on one significant element of a complex market to the exclusion of another significant element is inappropriate, resulting in an inadequate reflection of the market as a whole.

Lichtblau and Odell each agree that the volume-weighted third-party sales of Phillips Group, as reflected in column (d) of the appendix, represent highly significant values in the search for the value of Ekofisk crude oil. These spot and term transactions were negotiated at arm’s length. Actual sales are generally the best evidence of fair market value and must be accorded considerable weight. McGuire v. Commissioner, 44 T.C. 801, 808 (1965); Avery v. Commissioner, 3 T.C. 963, 973 (1944). Therefore, we find the combined actual third-party sales of the Phillips Group members to be the most relevant and useful value indicators in determining the fair market value of Ekofisk crude oil. The relative scarcity of third-party sales lends additional support for Norway’s use of the norm price system. We find that given these market circumstances, evidence of third-party sales is the type of evidence that is least likely to create distortions. We find it significant that these sales include all the third-party transactions occurring among all Phillips Group members during these 2 years.

Respondent argues that the Phillips Group’s third-party sales prices do not in fact “approximate” Norway’s norm price determinations, as such value estimations must be nearly exact or may only slightly exceed fair market value in order to approximate fair market value. Respondent contends that the definition of the term “approximates” should be construed narrowly. We feel that determinations involving the question of whether the operation of a gross receipts method approximates fair market value should be left to a court’s discretion without resorting to an inflexible mathematical rule that could not possibly consider a sufficiently large enough number of the various relevant market factors that a court may need to reflect upon in any given valuation decision. We will not entertain a specific definition of the word “approximates”; however, we note that valuation itself is far from an exact science. Wolfsen Land & Cattle Co. v. Commissioner, 72 T.C. 1, 19 (1979). We have stated that valuation is frequently an issue that is inherently imprecise and capable of resolution only by a Solomon-like pronouncement. Messing v. Commissioner, 48 T.C. 502, 512 (1967). Valuation is necessarily an approximation. Anderson v. Commissioner, 250 F.2d 242, 249 (5th Cir. 1957), affg. T.C. Memo. 1956-178.

Respondent points out that in the petroleum industry, a discrepancy of only a few cents per barrel can produce value differences worth millions of dollars. The following chart utilizes the barrels of Ekofisk crude oil sold quarterly by the Phillips Group during the years in issue to reveal the differential between the gross receipts produced when norm prices are used and the gross receipts produced when actual sales prices are used:

Volume (barrels sold) Norm prices Gross receipts Third prices Gross receipts actual Dif-Difference gross receipts

(a) (b) (a)x(b) (c) (d) (a)x(d) (e) (bMd) (f) (a)x(f) or (c)-(e) (g)

1981

1 10,063,086 $40.00 $402,523,440 $39.94 $401,919,655 $.06 $603,785

2 9,052,817 39.30 355,775,708 37.03 335,225,813 2.27 20,549,895

3 8,917,283 35.75 318,792,867 35.40 315,671,818 .35 3,121,049

4 8,635,529 36.75 317,355,691 36.81 317,873,822 (.06) (518,131)

Volume (barrels sold) Norm prices Gross receipts norm Third party sales prices Gross receipts actual Dif- Difference gross ference receipts

(a) (b) (a)x(b) (c) (d) ('a)x(d) (e) (b)-(d) (f) (a)x(f) or (c)-(e) (8)

1982

Q1 8,706,721 35.05 305,170,571 36.38 316,750,510 (1.33) (11,579,939)

2 8,608,616 32.50 279,780,020 33.00 284,084,328 (.50) (4,304,308)

3 8,424,233 34.15 287,687,557 34.06 286,929,376 .09 758,181

4 6,908,456 34.00 234,887,504 33.84 233,782,151 .16 1,105,353

Total 2,501,973,358 2,492,237,473 9,735,885

When the eight quarters in the period before us are combined, gross receipts determined under the norm price system exceed actual receipts by approximately (and we note by merely) $10 million, and total gross receipts approximate $2V2 billion. While the largest differential, 6 percent, occurs in the second quarter of 1981, we find that eight quarters are before us and the overall differential is less than .4 percent of total gross receipts. This differential is remarkably small given the volatility that occurred in the market during the years in issue. We do not accept the notion that the operation of the norm price method of determining gross receipts did not in fact approximate the fair market value of actual gross receipts for Ekofisk crude oil. Respondent alleges that such an average can only be determined over a reasonable period. Respondent defines a reasonable period as more than 2 years. Respondent seeks support in examples 32 and 34 of section 4.901-2(e), Temporary Income Tax Regs. We find no support for such a position, as these examples do not address this issue even though the words “a reasonable period” appear therein.

Respondent also argues that petitioners have failed in their burden of proof by failing to establish that all crude oil flowing from the Norwegian sector of the North Sea did in fact approximate fair market value; namely, crude oil production from the Statfjord and Murchison fields, respectively referred to as Statfjord and Brent Blend crude oils. We disagree. The ppb determined norm prices for separate geographic field clusters utilizing the same transportation facilities. We find the ppb’s more narrow and focused analysis of a grouping of market participants better reflected the prices which could occur between independent parties under free market conditions. Every grade of crude oil is different in chemical composition and quality. The relative value of one crude oil versus another is affected by, among other things, its physical and chemical characteristics, locational differences, and the relative prices of the various refined products that can be made from the various crude oils. Exxon Corp. v. Commissioner, T.C. Memo. 1993-616. We do not find the fair market value of Statfjord or Brent Blend crude oils to be controlling in the determination of the fair market value for Ekofisk crude oil.

Finally, respondent asserts that the history of complaints advanced by members of the Phillips Group and others regarding the process by which norm prices were determined and the ultimate norm price determinations demonstrated that norm prices did not in fact approximate fair market value. We disagree again. It can be stated without uncertainty that it is the taxpayer’s lot to be discontented when issues of taxation are involved. The Norwegian norm price procedures appear to have been fair and reasonable, they were carried out in good faith, and the PPB’s only aim was to fairly reflect gross receipts from petroleum upon careful examination and consideration of all market evidence.

The Phillips Group’s proposals for norm prices, as reflected in column (b) of the appendix, were a combination of values including official selling prices, contract, and spot sales and the value of Ekofisk crude relative to designated marker crude oils. The group’s norm price proposals were without question heavily weighted by the Phillips Group’s third-party sales evidence. Those subject to norm price determinations were provided with the opportunity to present evidence in the form of initial proposals and were later invited to further advance their positions before the ppb in at least two meetings. The regulations also provided sufficient rights of appeal. Given this unique and inherently adversarial process, the Phillips Group’s proposals were remarkably close to actual norm price determinations. We note that when overall gross receipts are calculated based on the Phillips Group’s norm price proposals, total gross receipts over the 2-year period closely approximate total gross receipts based on final ppb norm price determinations, as well as total gross receipts based on the Phillips Group’s third-party sales. The discrepancy in gross receipts from our determination of fair market value and Phillips Group’s norm price proposals is merely $6 million dollars, or a barely noticeable .2-percent differential. We are convinced that the norm price proposals of the Phillips Group, as well as the procedures conducted in good faith by the PPB and the resulting norm price determinations, resulted in serious evidence of fair market value. We ultimately find that gross receipts as determined pursuant to Norwegian norm price procedures during the years in issue, in fact, produced an amount that approximated fair market value.

(b) Net Income

A foreign charge meets the net income requirement if the base of the charge is computed, without substantial deviation, by reducing gross receipts by expenses and capital expenditures attributable, under reasonable principles, to such gross receipts. Sec. 4.901-2(c)(4), Temporary Income Tax Regs. To be creditable, a foreign tax must be the substantial equivalent of an income tax as that term is understood in the United States. Commissioner v. American Metal Co., 221 F.2d at 136. The concept of income has been uniformly restricted to a gain realized or a profit derived from capital, labor, or both. Keasbey & Mattison Co. v. Rothensies, 133 F.2d 894 (3d Cir. 1943). An “income tax” is a tax on gain or profits, and it encompasses foreign income taxes designed to effectively reach some net gain or profit. Bank of America Natl. Trust & Sav. Association v. United States, 198 Ct. Cl. 263, 459 F.2d 513, 517-519 (1972). Failure to take into account operating expenses normal to the active conduct of business indicates that the government involved did not design the tax to reach net profit. In determining whether a tax reaches net gain, it is important to determine the expenses which the foreign tax takes into account. Net profit subject to foreign tax must be analogous to the type of net profit reached by the U.S. income tax. Inland Steel Co. v. United States, 230 Ct. Cl. 314, 677 F.2d 72, 80, 84 (1982). The foreign method of determining tax need not conform strictly to the manner in which income taxes are computed under our own laws. Santa Eulalia Mining Co. v. Commissioner, 2 T.C. 241, 245 (1943). The deductibility of expenses, however, cannot be limited to the direct costs of operations (in this case, specific mining extraction expenses), but must also include expenses normally incident to the general conduct of the business. Keasbey & Mattison Co. v. Rothensies, supra.

With each of the Norwegian taxes, gross receipts for crude oil were determined by applying norm prices to the number of barrels of oil passing the norm price point during the year. All other income was taxed when realized at actual prices. As we have determined that the Norwegian norm prices approximated fair market values, they do not deviate from the definition of gross receipts; therefore, they do not affect our decision that the Norwegian taxes reach net income.

Pursuant to the GTA, deductible expenses were broad and included costs incurred to acquire, secure, and maintain income. Upon examination of a summary of petitioners’ financial accounts and their Norwegian tax returns, it appears that the restrictions on the deductibility of expenses were fewer than those found in the U.S. Internal Revenue Code. Annual changes in inventories, receivables, and debt were accounted for. Sizable and permanent expenditures for property, plant, and equipment were capitalized and depreciated. Gains from the sale of assets were also taxable unless a taxpayer qualified for an exemption.

The modifications made by the PTA included gross receipts based on norm price determinations; accelerated depreciation rates for petroleum producers; the addition of the 100-per-cent uplift allowance in the case of the national and special charges, but the elimination of additional maximum depreciation allowances of 50 percent; the extended carryover periods for NOL’s; the 50-percent limitation in offsetting onshore losses against offshore income, the additional option to carry over offshore losses for future use against subsequent offshore income, instead of utilizing such losses as current offsets against onshore income, the shortened period of deferral in paying tax installments; and the nondeductibility of contributions for scientific research; as well as sales commissions and similar costs paid or allocated between related parties.⁹

Respondent argues that significant deductions and losses were disallowed in the computation of each Norwegian tax base; therefore, none of the three tax bases are likely to reach net income in the U.S. sense. The most significant dis-allowances respondent addresses are the lack of deductibility of the three Norwegian taxes themselves when calculating the taxable base for another Norwegian tax, the nondeductibility of related-party sales commissions, and the 50-percent onshore NOL offset limitation.

Respondent argues that due to the fact that each of the Norwegian taxes (municipal, national, and special) results in significant costs, and as none of these “disguised” royalties is deductible in determining the taxable bases for either of the other charges, these charges do not reach net income. While we recognize that the disallowance of mineral royalty deductions would significantly increase the liability of persons engaged in mineral extraction, and that such nondeductibility would substantially deviate from our own definition of net income, respondent’s argument fails due to our determination that such charges are indeed taxes and not royalties. Additionally, the Norwegian GTA provides for the deductibility of royalties and area fees. Example 41 of the regulations cited above is not applicable. Also, contrary to respondent’s assertions, example 27 supports petitioners’ position as it reiterates the principle that the failure of a charge to allow the deduction of an income tax imposed on the same gross receipts is not a substantial deviation from the definition of net income.

The pta’s disallowance of deductions for sales commissions, discounts, and costs paid or allocated between related petroleum companies simply denies deductions for expenses which are already suspect due to the common interests that exist between the parties. Such costs could have been disallowed pursuant to GTA provisions that allowed Norwegian authorities to disregard these costs under such circumstances (compare section 482 of the Internal Revenue Code). Norway apparently chose to eliminate this questionable deduction for the same reasons it developed the norm price system. We find that such costs, even if they were legitimate, would be insignificant, and do not cause a substantial deviation from the U.S. definition of net income.

We have already addressed the 50-percent limitation regarding offsetting onshore losses with offshore income, and have found such limitation not to be the equivalent of a denial of a deduction with regard to the municipal and national taxes, as onshore losses could be carried forward and utilized in future years against onshore income for a period of 10 years. The same reasoning applies to the special tax even though onshore losses are never deductible in determining the special tax base. Such onshore losses still enjoy 10 years of carryforward possibilities against subsequent onshore income. Such a long period of carryforward provides adequate time to utilize such losses. Our circumstances herein are quite unlike those of example 32, where country X prohibited the filing of consolidated returns between related corporations, and required every oil well to be operated through a separate corporation. (The example found that the taxes paid by companies engaged in oil extraction would be significantly higher, and an unlimited loss carryover period was useless, when income could not be foreseen to emanate from a dry hole.)

Further, the allocation rules were not intended to, and did not effectively or inappropriately, “ring a fence” around the production activities of the shelf district. Both before and after amendments to allocate similarly situated items of income and expense to the same district, financial items that were directly related to shelf activities were predominately allocated to the shelf district, either as directly related items, or as items allocated proportionately among district net incomes for which the shelf district undoubtedly captured the lion’s share. Additionally, example 33 allows countries to segregate and separately tax unrelated lines of business of a single taxpayer without violating the net income test.

We have no difficulty determining that all three Norwegian taxes (municipal, national, and special) reach net income in the U.S. sense, as each is computed, without substantial deviation, by reducing a taxpayer’s gross receipts with the expenses and capital expenditures attributable thereto, including costs directly related to the exploration for and exploitation of petroleum resources on the Norwegian Continental Shelf. Consequently, these taxes are the substantial equivalent of a net income tax, as that term is understood in the United States. Respondent’s opposition to the special tax may emanate from Norway’s imposition of an additional layer of taxation specifically targeted at a particular industry. This Court has sanctioned additional layers of tax that are not generally imposed. Emerson Elec. Manufacturing Co. v. Commissioner, 28 T.C. 1090 (1957). Norway’s enactment of the PTA is completely in line with its purpose of adding an additional layer of income taxation to an industry that Norway found exceedingly profitable. In 1917, during World War I, our country enacted an excess profits tax, principally to meet the extraordinarily large appropriations urgently needed for military and naval establishments and fortifications. Revenue Act of 1917, ch. 159, 39 Stat. 1000. This excess profits tax was imposed in addition to other taxes, specifically, in addition to the general income tax, and was imposed on the basis of net income shown on a taxpayer’s income tax returns, at a rate of 8 percent of such net income that exceeded the combined sum of $5,000 and the amount of capital a taxpayer had invested in the United States. Revenue Act of 1917, secs. 201-203, 39 Stat. 1000-1001. A similar tax, but at much higher rates, was enacted during World War II, and for the same reasons. Revenue Act of 1942, ch. 619, 56 Stat. 798, 899.

We hold that the Norwegian special tax was designed to tax net profits, that is, it was a “profits” tax within the meaning of section 901, and it was also designed to capture excessive profits; therefore, it is most appropriately described as an “excess profits” tax, as Congress has used that term when it has been written into the Internal Revenue Code.

With this ultimate determination, we hold that the Norwegian municipal and national taxes are creditable as “income” taxes, and the “special” tax is creditable as an “excess profits” tax pursuant to section 901. Due to our determinations herein, we need not consider the parties’ arguments concerning section 903.

An order will be issued restoring this case to the general docket for resolution of the remaining issues.

APPENDIX

Different Factors Relied On

Norm Norm price proposal Third Ekofisk Difference party sales Difference spot prices Difference

(a) (b) (a)-(b) (c) (d) (a)-(d) (e) (f) (a)-(f) (g)

Qtr. 1 $40.00 $39.90 $.10 $39.94 $.06 $39.19 $.81

Qtr. 2 39.30 38.70 .60 37.03 2.27 34.15 5.15

Qtr. 3 35.75 35.60 .15 35.40 .35 35.57 .18

Qtr. 4 36.75 36.55 .20 36.81 C.06) 36.84 (.09)

Qtr. 1 35.05 34.64 .41 36.38 (1.33) 33.35 1.70

Qtr. 2 32.50 32.40 .10 33.00 (.50) 33.36 (.86)

Qtr. 3 34.15 34.07 .08 34.06 .09 33.35 .80

Qtr. 4 34.00 33.86 .14 33.84 .16 32.81 1.19

Total 287.50 285.72 1.78 286.46 1.04 278.62 8.88

by the Expert Witnesses

Spot prices BNOC basket of Ekofisk Forties 16 crudes Difference Spot EER Difference term prices Difference prices Difference

(h) (a)-(h) 0) (a)-(f) (k) (D (a)-(l) (m) (n) (a)-(n) (o)

$38.64 $1.36 $39.25 $.75 $40.00 $39.25 .75

34.10 5.20 35.02 4.28 39.49 ($.19) 38.50 .80

34.95 .80 35.41 .34 35.75 35.00 .75

36.26 .49 36.76 (.01) 36.73 .02 36.00 .75

30.81 4.24 32.42 2.63 34.98 .07 34.42 .63

33.22 (.72) 34.18 (1.68) 32.41 .09 31.83 .67

33.13 1.02 33.57 .58 34.25 (.10) 33.50 .65

32.40 1.60 33.45 .55 34.25 (.25) 33.50 .50

273.51 13.99 280.06 7.44 287.86 (.36) 282.00 5.50

1 The determination of whether these charges are income taxes in the U.S. sense is the principal issue in this case. Our occasional use of the term “tax” is for ease of discussion only.

2 Cf. sec. 482,1.R.C.

3 See supra sec. 2 of our findings.

4 Compare secs. 561 — 565,1.R.C.

5 In our parlance, we might say an annual “revenue act”.

6 So shown by respondent’s exhibit; the totals are not the sum of the individual charges; the reasons are unexplained.

7 “Income tax” as used in this discussion includes any income, war profits, or excess profits tax. Sec. 4.901-2(a)(l), Temporary Income Tax Regs.

8 We were impressed by each of the three Norwegian experts who testified (in English, without the aid of interpreters) at the trial of this case in Washington, D.C. Their testimony was knowledgeable and cogent.

9 Although it may have lengthened this opinion somewhat, we have thought it desirable to include somewhat more detailed findings as to the characteristics of the three Norwegian taxes, to show their comparability to U.S. taxes.