*123 Decision will be entered under Rule 155.
Petitioner is an integrated oil company. Following the enactment of the Crude Oil Windfall Profit Tax Act of 1980, Pub. L. 96-223, 94 Stat. 229, petitioner changed its method of calculating "taxable income from the property" under
*372 The Commissioner determined deficiencies in petitioner's windfall profit tax under
| Taxable quarter ended -- | Deficiency |
| 3/31/80 | $ 12,050,373 |
| 6/30/80 | 54,129,746 |
| 9/30/80 | 73,773,559 |
| 12/31/80 | 101,841,218 |
Alternatively, the Commissioner determined a deficiency in petitioner's windfall profit tax under
The issues in this case concern the attribution and allocation of expenses for the calculation of the taxable income from petitioner's oil and gas properties under
FINDINGS OF FACT
Most of the facts have been stipulated. The stipulations of fact and accompanying exhibits are incorporated by this reference.
Shell Oil Co. (petitioner) is a corporation organized under the laws of Delaware with its principal office in Houston, Texas. Petitioner is an integrated oil company involved in all facets of the petroleum industry from exploration *373 through development and production to purchasing, refining, *127 manufacturing, transportation, and marketing. During the taxable periods in issue, petitioner was organized into two primary organizations referred to as the "Products organization" and the "Exploration and Production" organization. The Exploration and Production organization had the responsibility for finding and producing crude oil and natural gas. The Products organization included all other activities of petitioner such as refining, marketing, and the manufacture of chemicals derived, in whole or in part, from petroleum. In addition, petitioner had an administration group composed of service departments such as employee relations, legal, public affairs, and finance departments, which supported the two operating organizations.
The Exploration and Production organization was divided into four regions: Eastern Region Operations, Western Region Operations, Mining Operations, and International Operations. Mining and International Operations contributed less than 1 percent of the total gross income from the Exploration and Production organization and their activities are generally not germane to the issues in this case. During the taxable year 1980, Eastern Region Operations and*128 Western Region Operations were composed of three divisions, each of which was separately engaged in oil and gas exploration, development, and production activities within defined geographic areas.
The search for, acquisition, and exploitation of oil and gas reserves may be referred to as the exploration and production cycle. Petitioner's exploration and production cycle began when its geologists or geophysicists selected areas with potential oil and gas reserves. If petitioner decided to investigate these potential reserves further, the exploration and production cycle entered the "probe" stage. During this stage, preliminary studies were made by the exploration department, including regional geological studies and seismographic testing, and by the land department, which determined the amount of acreage available in the area and the probable cost of the mineral rights in terms of lease bonuses and royalty provisions. The production department was also involved at this stage providing information for the economic analysis to determine whether the probe *374 should be developed further. When the exploration department decided, with the input of the land and production departments, *129 that a probe warranted further exploration, it was termed a "play." At this stage, the exploration department obtained more seismographic data and attempted to map multiple prospects within the play so petitioner could benefit from any successful development efforts. At this stage, petitioner's exploration, land, and production departments pooled their information in an attempt to calculate the present value of the production department profit on development, or PDPOD, for a prospect. If the decision was made to discontinue exploratory efforts, the land department assumed primary responsibility for dropping the prospects either through farm-out arrangements or surrender of the leases. If petitioner decided to drill one or more exploratory or wildcat wells, the exploration department authorized the land department to acquire mineral leases in specified areas. The exploration department then sent a request to the production department for a detailed plan for drilling the wildcat well or wells, and an estimate of the drilling cost. The exploration department then authorized and provided funds for the drilling of the wildcat well or wells. The production department drilled the wildcat*130 well or wells typically through use of a contract driller.
After a wildcat well was drilled, the production department evaluated the well to determine if it appeared to be capable of producing oil or gas or both in commercial quantities. Many such wells were dry holes and clearly incapable of commercial success; others were clearly commercially productive wells. In cases where it was not obvious whether the well was capable of producing oil and gas in commercial quantities, the exploration department and the production department worked together to assess the commercial potential of the well. Disputes as to whether an exploratory well was commercially productive were resolved by the division general manager.
If it were determined that an exploratory well was capable of producing oil and gas in commercial quantities, the supervision of the prospect was transferred from the exploration department to the production department, *375 which was responsible for developing the prospects included in the play. The production department then drilled wells to fully exploit the newly discovered reserves. The exploration department often remained involved during the development phase *131 by making additional seismographic tests and reinterpreting earlier exploratory data with the additional information provided by the wildcat, and by advising the production department concerning the locations of the wells.
The land department continued to be involved during the production phase of the exploration and production cycle. The land department maintained petitioner's lease files and was responsible for compliance with provisions of the mineral leases, including payment of the proper royalties, preparation and maintenance of division orders reflecting the current ownership of mineral interests, compliance with continuous drilling obligations, required shut-in payments, and other contractual obligations assumed by petitioner under the leases. The land department, with assistance from the legal department, also prepared joint venture agreements and unitization agreements.
When oil and gas reserves were depleted so that production could not be maintained economically, perhaps following secondary and tertiary recovery efforts, the exploration department could reevaluate the field. Advanced exploration techniques and data might prompt efforts to discover deeper reserves. All*132 three departments within petitioner's Exploration and Production organization, exploration, land, and production, were involved in the decision to cease production efforts, and, if so, the land department had the responsibility to surrender the leases involved.
During the entire exploration and production cycle, petitioner's exploration, production, and land departments worked together on an interrelated and interdependent basis to achieve the single objective of the Exploration and Production organization: to find and produce oil and gas.
If reserves that are being depleted by production are not replaced with new reserves, a producer of oil and gas may be viewed as liquidating itself. Therefore, a producer engaged in the ongoing production of oil and gas must constantly acquire new reserves. The need for new reserves causes the exploration and production cycle to be repeated *376 continuously. However, reserves may also be replaced, often more cheaply, by the purchase of proven reserves or producing properties from others. While petitioner continued its own exploratory efforts, it also purchased substantial reserves by the acquisition of Belridge Oil Co. (Belridge) in 1979.
*133 In May 1979, the board of directors of Belridge adopted a competitive bidding program to solicit offers for the acquisition of Belridge. Petitioner submitted a bid and in September 1979 was selected as the winning bidder. Effective in December 1979 petitioner's wholly owned subsidiary, Kernridge Oil Co. (Kernridge), acquired all of the stock of Belridge for $ 3,624,105,110 in cash, $ 29,166,890 in promissory notes, and certain rights to buy fractional interests in oil properties owned by Belridge. In January 1980, Belridge was liquidated and its assets were transferred to Kernridge.
To finance the purchase of Belridge, Shell entered into credit agreements with consortiums of domestic and foreign banks. In October 1979, petitioner entered into a revolving credit agreement with a consortium of domestic banks led by Chase Manhattan Bank under which petitioner borrowed a total of $ 2,100,000,000 during December 1979 and January 1980 (the Chase loan). In November 1979, petitioner entered into a revolving credit agreement with a consortium of foreign banks under which petitioner borrowed a total of $ 900 million during December 1979 (the Foreign loan). The remaining funds necessary*134 for the acquisition of Belridge were obtained by petitioner from the sale of receivables to a wholly owned financing subsidiary of petitioner, Shell Credit, Inc., in the amount of $ 350 million, and a short-term portfolio liquidation yielding $ 300 million.
In late 1979 and early 1980, petitioner had triple-A credit ratings from Moody's Investors Service and Standard & Poor's. It was not necessary for petitioner to mortgage assets to support its borrowings. Because of its financial strength, lenders were willing to make loans to petitioner on its general credit and the loans to petitioner by Chase and the Foreign loan were made on petitioner's general credit. Neither the Chase loan nor the Foreign loan created for the lenders a security interest in, or a lien, charge, pledge, or encumbrance upon any specific properties or assets of *377 petitioner. Further, neither loan created any lien on the stock or assets of Belridge or a preferential right to income. Petitioner was not restricted from selling or pledging any specific assets, including its interest in Belridge.
The Chase credit agreement included the following provision:
Purpose [Shell] shall use the proceeds of *135 loans under this agreement solely for the purpose of making payments directly or indirectly with respect to the acquisition of Belridge.
The Foreign credit agreement contained a similar clause. Nevertheless, petitioner's use of the proceeds of the loans for a purpose other than the acquisition of Belridge would not have constituted a default under any provision of the Chase or Foreign credit agreements.
All of the proceeds of the Chase loan and the initial $ 900 million drawn on the Foreign loan were deposited in petitioner's general corporate bank account maintained at Chase Manhattan Bank and were commingled with other funds of petitioner in this account. However, these deposits were, in general, followed by identifiable transfers of funds to Kernridge, which Kernridge used to purchase Belridge stock.
During the period from December 1979 through April 1980, petitioner made multiple transfers of funds to Kernridge aggregating $ 4,010,373,621. Kernridge used $ 3,624,105,110 of the funds transferred to it to make the cash payments to Belridge shareholders. Petitioner treated $ 3,185,512,547 of the total transfers as a contribution to the capital of Kernridge and the remainder, *136 $ 824,861,074, as a loan. Kernridge executed a promissory note for this loan.
In April 1980, Kernridge borrowed $ 1,750,000,000 from unrelated third parties in exchange for a production payment with respect to oil and gas properties obtained in the acquisition of Belridge. Although the sale of a production payment was clearly contemplated at the time petitioner negotiated the Chase loan and Foreign loan, petitioner was under no contractual obligation under those credit agreements to cause Kernridge to do so. On April 23, 1980, Kernridge paid $ 1,750,000,000 to petitioner. On the same day, petitioner made a payment of $ 1,750,000,000 against *378 the principal balance of the $ 2,100,000,000 Chase loan. The payment by Kernridge to petitioner was treated as repayment of the $ 824,861,074 loan, plus accrued interest. The remainder of the proceeds of the production payment paid to petitioner was ultimately treated as a return of capital.
Petitioner paid the remaining balance of the Chase loan by July 1980. Petitioner paid only accrued interest on the Foreign loan until July 17, 1981. At that time, petitioner began to make periodic payments of principal and to draw additional*137 funds under the Foreign loan. The principal balance of the Foreign loan was not fully repaid until June 1982. From December 1979 through June 1982 a total of $ 1.8 billion was borrowed and repaid under the Foreign loan. During the taxable year 1980, petitioner paid net interest on the Chase and Foreign loans of $ 145,585,640.88 (interest expense of $ 181,222,405 less interest of $ 35,636,764.12 received by petitioner from Kernridge).
The acquisition of the Belridge properties increased petitioner's estimated proven oil reserves by approximately 600 million barrels and natural gas reserves by 383 billion cubic feet. The funds transferred to Kernridge in excess of the costs of acquiring Belridge were used to improve production from oil properties of Belridge. Immediately after Belridge was acquired, petitioner began a program of drilling additional wells and enhanced recovery measures to increase the production of oil and gas. These efforts succeeded in substantially increasing the average daily production from the properties.
Subsequent to 1974, petitioner's deductions for percentage depletion decreased substantially. The method used by the petitioner to compute and allocate*138 amounts in computing taxable income from the property for purposes of the deduction for percentage depletion under
Petitioner filed Quarterly Federal Excise Tax Returns, Form 720, and Windfall Profit Tax, Form 6047, for the quarters ended March 31, 1980, June 30, 1980, and September *379 30, 1980, on which petitioner reported liability for WPT in the amounts of $ 63,503,550.85, $ 212,017,960.10, and $ 266,600,000, respectively. Petitioner filed Forms 720 and 6047 for the quarter ended December 31, 1980, on which it reported WPT liability of $ 331,978,519.48, from which petitioner subtracted "Estimated Net Income Limitation Adjustment for 1980" in the amount of $ 100 million. The claimed net income limitation adjustment and other adjustments resulted in net WPT liability for the fourth quarter of 1980 in the amount of $ 210,400,000. Petitioner paid all net amounts shown on Forms 720*139 for the 1980 calendar quarters by periodic deposits.
Petitioner filed a consolidated U.S. Corporation Income Tax Return, Form 1120, for the taxable year 1980. With its return it filed Computation of Overpaid Windfall Profit Tax, Form 6249. On that form it claimed overpayment of WPT resulting from the net income limitation of
By combining the amounts claimed on Form 6249 filed with petitioner's 1980 Federal income tax return and on petitioners excise tax return for the fourth quarter of 1980, petitioner claimed a total net income limitation benefit with respect to its WPT liability for 1980 in the amount of $ 241,794,896. In calculating its net income limitation benefit, petitioner, for the first time, allocated overhead incurred above the division level to its producing and nonproducing properties. *140 In determining its taxable income from the property for purposes of the net income limitation upon the deduction for percentage depletion and, with certain changes mandated by statute, the net income limitation upon the WPT, petitioner allocated certain indirect expense amounts to its oil producing properties using a multistep allocation process.
The first level of allocation was between the Exploration and Production organization and the Products organization. *380 At this level, expenses including certain head office overhead, State franchise and income taxes, and interest were allocated based upon the relative fair market value of the assets of the respective organizations. At the second level of allocation, petitioner added to the amounts allocated to the Exploration and Production organization at the first level certain regional overhead costs, indirect land and exploration expenses, and certain abandonment losses. This total was allocated to the four Exploration and Production regions, Eastern Region Operations, Western Region Operations, International Operations, and Mining Operations, based upon their relative gross income. At the third level, petitioner added division*141 level overhead and allocated the total among the six oil and gas producing divisions based upon relative production. At the fourth level, the amounts were allocated between producing and nonproducing properties within each division based upon relative production. Finally, amounts allocated to the producing properties were allocated between oil and gas production.
The inclusion for the first time of overhead amounts incurred above the division level and other indirect expenses dramatically increased the costs allocated to petitioner's approximately 3,290 oil and gas properties for purposes of calculating taxable income from such properties. Amounts allocated to petitioner's producing and nonproducing oil and gas properties for the purpose of computing taxable income from the property for the years 1975 to 1980 is as follows:
| Amounts allocated to petitioner's | |
| Year | producing and nonproducing properties |
| 1975 | $ 110,615,577.54 |
| 1976 | 104,079,383.10 |
| 1977 | 114,172,515.19 |
| 1978 | 132,038,397.51 |
| 1979 | 133,535,727.94 |
| 1980 | 1,022,045,936.17 |
Respondent, in his notice of deficiency mailed to petitioner, disallowed the entire net income limitation benefit claimed by petitioner on its*142 Federal excise tax return for the fourth quarter of 1980 and Federal income tax return for the taxable year 1980. Following concessions, the parties have reached substantial agreement as to the costs to be *381 included in the calculation of taxable income from the property and the methods of allocating indirect costs for purposes of the WPT net income limitation. The parties agree that, at the first level of allocation, overhead items identified as corporate assigned, corporate support expense, and miscellaneous corporate totaling $ 100,767,655 should be allocated between the Products and Exploration and Production organizations using a method they have identified as a modified direct expense method. State income and franchise taxes in the amount of $ 59,750,998 are to be allocated between Products and Exploration and Production based upon relative net income. The parties also agree that a portion of the net interest expense (interest expense less interest income) totaling $ 74,355,255 unrelated to the Belridge acquisition shall be allocated between Products and Exploration and Production based upon relative capital expenditures.
The expenses allocated to the Exploration*143 and Production organization at the first level of allocation are to be combined with indirect Exploration and Production organization expenses identified as research and development expenses and miscellaneous regional expenses totaling $ 45,739,677, plus any additional amounts determined by this Court, and allocated to petitioner's four Exploration and Production regions based upon relative gross income. Under this method, 48.61 percent and 51.03 percent of all such indirect expenses shall be assigned to Eastern Region Operations and Western Region Operations, respectively. Amounts allocated to the Eastern and Western regional operations will be further allocated, along with division level overhead, to each of the six divisions thereunder based upon relative gross income. Within each division, costs are to be allocated between producing and nonproducing properties using the stipulated modified direct expense method. Finally, costs allocated to producing properties are to be divided between oil and gas production based upon relative production treating 20,000 cubic feet as equal to one barrel of oil.
The parties have also reached substantial agreement as to the costs to be included*144 in the stipulated modified direct expense allocation base. They have stipulated that the *382 direct expenses of producing and nonproducing properties include amounts identified with the following accounts totaling $ 617,969,613:
| Account | Description |
| 1010 | Direct lease expense |
| 1015 | Well repair and maintenance |
| 1017 | Well reconditioning and recompletion |
| 1061 | Insurance |
| 1072 | Property taxes |
| 1073 | Severance taxes |
| 1074 | Sales and use tax |
| 1098 | Gas lift gas expense |
| 1099 | Gas injection expense |
| 1401 | Line and meters |
| 1431 | Plant supervision |
| 1461 | Insurance |
| 1472 | Property taxes |
| 1473 | Severance taxes |
| 1474 | Sales and use tax |
They have stipulated that of the above total direct expenses of producing and nonproducing properties, $ 607,041,881 are direct expenses of producing properties, and $ 10,927,732, are direct expenses of nonproducing properties.
No income tax issue, such as the deductibility of any of the above expenses, is at issue in this case.
Petitioner was not an "independent producer" within the meaning of section 4992(b)(1) with respect to any calendar quarter of 1980.
OPINION
Despite the numerous concessions by the parties and extensive stipulations of fact, material*145 disagreement remains concerning the expenses to be considered and the method of allocating indirect expenses in calculating taxable income from the property for purposes of the WPT net income limitation. The parties' disagreements fall into two broad categories: (1) What items are to be attributed, directly or indirectly, to producing properties, and consequently, to barrels of oil; and (2) whether IDC, WPT liability, and geological and geophysical (G&G) expenditures should be included in the stipulated modified direct expense method. Before examining the specific issues raised by the parties, *383 some background on the WPT net income limitation is appropriate.
In response to phased decontrol of crude oil prices announced by President Carter in April 1979 and increased world-wide crude oil prices, Congress determined that the additional revenues or "windfall" that U.S. oil producers would thereby receive were an appropriate object of taxation. H. Rept. 96-304 (1979),
A net income limitation on depletion deductions first appeared in the Revenue Act of 1921, ch. 136, secs. 214(a)(10), 234(a)(9), 42 Stat. 227, 239, 254, as a limitation on the allowance for discovery depletion, the statutory precursor of percentage depletion. *149 The depletion deduction based upon discovery value was originally limited to the "net income, computed without allowance for depletion, from the property," but was later reduced to 50 percent of such net income. Revenue Act of 1924, ch. 234, sec. 204(c), 43 Stat. 253, 258-260. When the percentage depletion allowance for oil and gas wells was enacted in 1926, a 50-percent net income limitation was also applied. Revenue Act of 1926, ch. 27, sec. 204(c)(2) 44 Stat. 9, 14-16. See
The percentage depletion NIL and the WPT NIL require that the income and deductions which constitute the taxable income from the property be identified. This calculation is then used to limit the allowable depletion deduction and, now, to limit the liability for WPT under
Current regulations under
(a) General rule. The term "taxable income from the property (computed without allowance for depletion)", as used in
Following the enactment of
Petitioner contends that net interest totaling $ 145,585,640.88 and identified with the acquisition of Belridge ($ 181,222,405 interest incurred on the Chase and Foreign loans less $ 35,636,764.12 interest received by petitioner from Kernridge) must be treated as general corporate overhead and allocated to all of its activities, including its Exploration and Production organization, and, consequently, producing properties. Petitioner thus argues that the net interest it incurred with respect to the Belridge acquisition is "financial overhead" within the meaning of
The term "taxable income from the property" is not defined in the Code. Although the NIL has been reenacted without substantive change since percentage depletion was enacted in 1926, there is apparently no helpful legislative history concerning the items that are deductible in calculating taxable income for this purpose, and the parties have failed to refer us to any. Regulations promulgated under
Petitioner argues that, consistent with cost accounting principles, interest expense is generally regarded as relating to all of the activities and assets of the enterprise. This contention is based upon the theory that money is fungible, *157 which, according to petitioner, leads to two other concepts. First, general-credit lenders are not concerned with how borrowed funds are used; instead, they are concerned with how they will be repaid. Second, use of borrowed funds on one project frees internally generated funds for use on other projects. Petitioner concludes that interest on unsecured, general-credit borrowings is overhead attributable to all of its activities and properties. Respondent's primary contention is that because of the stated purpose of the Chase and Foreign loans and the ease with which the proceeds of those loans are traced to the Belridge acquisition, the interest on such loans is a direct expense of the investment in Belridge and that it is not attributable to petitioner's "mining processes"; consequently, it may not be considered in calculating the net income from petitioners oil and gas properties.
Interest expense is clearly an allowable deduction in computing "taxable income from the property" under
*159
Respondent seeks to buttress his contentions by arguing that, because the proceeds of the Chase and Foreign loans may be readily traced to, and the purpose of those loans was stated to be for, the Belridge acquisition, the contested interest is a direct expense of that acquisition by analogy to section 265(2). Section 265(2) prohibits taxpayers from deducting interest that is incurred or continued to purchase or carry tax-exempt obligations. Under section 265(2), the taxpayer's purpose for incurring or continuing the indebtedness is the proper inquiry in deciding whether to attribute *390 interest expense to the purchase or carrying of tax-exempt obligations.
Inasmuch as
*163 Petitioner offered the testimony and reports of four witnesses qualified as experts regarding the proper cost accounting treatment of the contested interest. In general, we find the opinions of petitioner's experts persuasive, and their credentials unassailable. All four were of the opinion that the contested interest should not be treated as a direct expense of the acquisition of Belridge and that it is properly treated as general overhead of all of petitioner's activities.
Dr. Robert J. Koester, professor of accounting, director of the Center for Oil and Gas Accounting, and director of the master's in oil and gas accounting program at Texas Tech University, pointed out in his opinion that the contested interest could be a direct expense of the Belridge acquisition only if the debt that gave rise to the interest expense were secured by the asset in question and serviced only by the funds generated by that asset.
Dr. Roman L. Weil, professor of accounting and director of the Institute of Professional Accounting at the University of Chicago, reached a similar conclusion about the general conditions necessary for specific financing to be associated with specific assets or activities. *164 He stated that a principle of modern financial economics is that corporate investment decisions are independent of corporate financing decisions. According to Dr. Weil, in accounting terms, this means that generally all of the "equities" (liabilities plus owner's equity) finance all of the assets, the major exception being nonrecourse borrowing where the lender looks only to the cash-flow from a specific project for debt service.
Dr. Sidney Davidson, Arthur Young Distinguished Service Professor of Accounting, and former dean, Graduate School of Business, University of Chicago, in his report, emphasized that cost accounting recognizes that money, *392 whether from loans or any other service, is a fungible resource; funds ostensibly borrowed for a specific purpose free funds generated from operations and funds from other sources to be used for other purposes. Dr. Davidson, who testified as an expert on behalf of respondent in
Arthur L. Litke, CPA, former member of the Financial Accounting Standards Board, and former chief accountant, Federal Power Commission, generally echoed the conclusions of petitioner's other experts.
The opinions of petitioner's experts regarding the fungible nature of money has explicit support in regulations promulgated under
(2) Interest -- (i) In general. The method of allocation and apportionment for interest set forth in this paragraph * * * is based on the approach that money is fungible and that interest expense is attributable to all activities and property regardless of any specific purposes for incurring an obligation on*166 which interest is paid. This approach recognizes that all activities and property require funds and that management has a great deal of flexibility as to the source and use of funds. Normally, creditors of a taxpayer subject the money advanced to the taxpayer to the risk of the taxpayer's entire activities and look to the general credit of the taxpayer for payment of the debt. When money is borrowed for a specific purpose, such borrowing will generally free other funds for other purposes and it is reasonable under this approach to attribute part of the cost of borrowing to such other purposes. * * *
(ii) Allocation of interest. Except as provided in subdivisions (iii) and (iv) of this subparagraph, the aggregate of deductions for interest shall be considered related to all income producing activities and properties of the taxpayer and, thus, allocable to all the gross income which the income *393 producing activities and properties of the taxpayer generate, have generated, or could reasonably have been expected to generate.
The regulations under
(iv) Allocation of interest to specific property. (A) If the existence of all of the facts and circumstances described below is established, the deduction for interest shall be considered definitely related solely to the class of gross income which the specific property generates, has generated, or could reasonably have been expected to generate. Such facts and circumstances are as follows:
(1) The indebtedness on which the interest was paid was specifically incurred for the purpose of purchasing, maintaining, or improving the specific property;
(2) The proceeds of the borrowing were actually applied to the specified purpose;
(3) The creditor can look only to the specific property (or any lease or other interest therein) as security for payment of the principal and interest of the loan and, thus, cannot look to any other property or the borrower with respect to payment of the loan;
(4) It may be reasonably assumed that the return (cash flow) on or from the property will be sufficient to fulfill the terms and*168 conditions of the loan agreement with respect to the amount and timing of payment of principal and interest; and
(5) There are restrictions in the loan agreement on the disposal or use of the property consistent with the assumptions described in (3) and (4) of this subdivision (iv)(A).
Even though the above facts and circumstances are present in substance as well as in form, a deduction for interest will not be considered definitely related to specific property where the motive for structuring the transaction in the manner described above was without any economic significance.
If we were to analyze the Chase and Foreign loans under the exception provided above, the attribution of the contested interest expenses solely to the acquisition of Belridge would not be required because those loans were unsecured general credit borrowings. Neither the stock of Belridge nor its properties were pledged to secure these loans. Of course, the regulations quoted above have no applicability in the determination of "taxable income from the property." *394 Nevertheless, they support the opinions of petitioner's experts on the fungibility of interest*169 and the allocation of interest under rules of cost accounting. The notion that interest on general credit obligations, despite statements of purpose in the loan documents and the actual use of the borrowed funds, may be considered overhead attributable to all of a taxpayer's activities and properties is not a cold academic theory; it has found application in respondent's own regulations.
To the contrary, respondent's cost accounting expert, Dr. Edward B. Deakin, concludes that the contested interest expense is a direct cost of the Belridge acquisition and, hence, is not properly attributable to all of petitioner's activities. As a consequence, he would not allocate the contested interest as general corporate overhead. Like petitioner's experts, Dr. Deakin's professional credentials are impeccable; he is currently Price Waterhouse Centennial Professor in Accounting at the University of Texas at Austin. He points to accounting authorities which generally describe direct costs as those costs which are readily identified with or traced to a cost objective. He concludes that the contested interest meets cost accounting standards as a direct expense of the Belridge acquisition. In*170 support of this conclusion he points to the statements of purpose in the Chase and Foreign loans and the fact that the proceeds of the loan may be traced to the purchase of the Belridge stock.
We conclude that the attribution by petitioner of the interest expense that is identifiable with the Belridge acquisition to all of its activities is consistent with the requirements of
The parties disagree on how the following seven categories of expense, labeled by the parties as the seven disputed Exploration and Production organization expenditures, should be treated in the calculation of the taxable income from the property.
| Dry hole costs on abandoned and nonproducing properties | $ 112,968,960 |
| Geological and Geophysical expenditures incurred in 1980 | |
| and abandoned as worthless in 1980 (not capitalized to any | |
| property) | 37,004,566 |
| Geological and Geophysical expenditures incurred before | |
| 1980 and abandoned as worthless in 1980 (not capitalized | |
| to any property) | 28,640,065 |
| Lease bonuses capitalized to abandoned properties | 41,845,607 |
| Geological and Geophysical expenditures capitalized to | |
| abandoned properties | 15,392,113 |
| Other exploration department expenses | 53,965,802 |
| Land department expenses | 8,800,296 |
*396 Petitioner claims that the seven disputed Exploration and Production organization expenditures are to be treated as indirect Exploration and Production organization costs allocated, along with research and development expenses and miscellaneous regional expenses, *173 to its regional operations and, ultimately, to producing properties. Respondent contends that each of the above amounts is one of the following: (1) A direct expense attributable to activities other than oil and gas production, namely activities identified by respondent as the exploration activity or acquisition activity, (2) a direct expense attributable to nonproducing properties, or (3) overhead attributable to activities other than oil and gas production or to nonproducing properties.
We begin our consideration of the issues raised by the parties with respect to the seven disputed Exploration and Production organization expenditures by examining the dry hole costs in the amount of $ 112,968,960. The parties have stipulated that petitioner incurred deductible dry hole costs on certain of its abandoned and nonproducing properties during the last 10 months of 1980 totaling $ 112,968,960. 10 These dry hole costs represent either IDC deductible under
Petitioner contends that all of its exploration and production efforts are necessary for the production of oil and gas, and that, therefore, the cost of all exploration and production efforts, including unsuccessful efforts, should be attributed *397 to its producing properties. Petitioner points to the fact that it drills several dry holes for each well that produces oil and gas in commercial quantities. From this, petitioner asks us to conclude that the costs of drilling unsuccessful*175 wells, no matter where situated, is an indirect cost of producing oil and gas and, therefore, an indirect cost of its producing properties. We agree with petitioner in the abstract. 11 However, petitioner ignores the narrow focus mandated by the statute and the regulations. We conclude that these deductions are only attributable to the abandoned or nonproducing property on which they were incurred thereby precluding attribution of these deductions to petitioner's producing properties.
*176
Perhaps this point would be better made by way of example. Assume petitioner desires to identify the income and accumulate the costs attributable to its Onshore Division for purposes of calculating net income therefrom. The Onshore*179 Division, a profit center, is, therefore, the cost objective. Direct costs of exploration and production activity, including dry hole costs, incurred within the geographic area under the control of the Onshore Division, pursuant to petitioner's organizational structure, would, of course, be deducted from the gross income of the division. An allocable share of indirect division costs, i.e., those costs which benefit more than one division or are caused by the *399 activities of more than one division, would also be deducted from gross income. Petitioner would not, however, deduct any costs which are direct costs of petitioner's Rocky Mountain division. To do so would thwart the whole purpose of the exercise, to calculate the net income earned from the operations of the Onshore Division. Attributing the dry hole costs incurred on abandoned or nonproducing properties as indirect costs of producing properties would, likewise, thwart the requirements of
In support of its argument that all unsuccessful efforts to produce oil or gas must be attributed to its *180 producing properties, petitioner draws an analogy to the accounting concept of normal spoilage. According to one of petitioner's experts, some amount of spoilage or nonsalable product frequently arises as good salable product is produced. Where that spoilage is normal, the cost of spoilage is included in the overhead to be allocated to the cost of the good units of output. Petitioner has failed to demonstrate that the concept of normal spoilage is one that properly applies in accounting for oil and gas enterprises. More importantly, even if the concept of normal spoilage were applicable, we do not think it requires the attribution of the cost of unsuccessful efforts incurred on abandoned and nonproducing properties to producing properties. We are not persuaded by petitioner's expert on this point.
Our conclusions at this stage also resolve the issues regarding the deductibility of the remaining disputed Exploration and Production organization expenditures. G&G exploration expenditures that provide data leading to the acquisition or retention of a mineral property for mineral exploration generally must be capitalized and, along with leasehold costs, included in the basis upon *181 which cost depletion may be claimed.
Petitioner's Exploration and Production organization conducts its single activity, the search for and production of hydrocarbons, not only on its producing properties, but also upon geographic areas where petitioner does not yet own a mineral interest, or where petitioner owns a mineral interest, but where it has yet to produce oil or gas. Petitioner expends a considerable amount of G&G on probes and plays that it later decides are not worthy of further exploration or the acquisition of mineral interests. Petitioner generally follows respondent's view of the proper treatment of G&G costs. Accordingly, petitioner claimed a deduction of $ 65,644,631 for income tax purposes for abandoned G&G costs which had been incurred before and during 1980 and which had not been capitalized to any mineral interest. The abandoned non-capitalized G&G costs were identifiable with probes or plays under consideration by petitioner during 1980.
Petitioner repeatedly pointed out that it was not in the business of drilling dry holes or expending funds on G&G to discover that a probe, play, or property in which it has acquired*183 a mineral interest did not contain producible reserves. Obviously, we do not disagree. To the contrary, petitioner does not expend funds on G&G on probes or plays, or on IDC for exploratory wells unless it concludes that those efforts have a reasonable probability of leading to the commercial production of oil and gas. For example, during the exploration phase of petitioner's exploration and production cycle, its personnel calculate the present value of *401 the production department profit on development or PDPOD to assist them in deciding whether to pursue or abandon exploratory efforts. Each such probe, play, or nonproducing property is pursued with the expectation that it can yield successful producing properties. However, because the cost objective under
Provided a proper showing of abandonment has been made, G&G that has been capitalized to a mineral interest, along with capitalized leasehold costs, *184 is deductible for income tax purposes as losses under
The arguments of the parties differ somewhat with respect to the proper treatment of the exploration department indirect*185 expenses in the amount of $ 53,965,802. Therefore, we consider them separately. The proper tax treatment of exploration expenditures which cannot be identified with any individual property or properties such as salaries, depreciation, travel, and other expenses relating to G&G projects is unclear. See Burke, "What is Proper Treatment of Geological and Geophysical Costs?
Respondent argues that exploration undertaken prior to the acquisition of a mineral interest is an activity that falls outside of the meaning of the term "mining process" and constitutes*186 an "other activity" under
In support of his contentions regarding exploration as being outside the meaning of "mining processes," respondent relies upon
The Court pointed out that it perceived congressional intent to require that the depletion deduction be the same for both integrated miners and nonintegrated miners.
*189 Virtually all miners incur exploration costs to discover mineral reserves prior to extracting those reserves. In the few examples relied upon by respondent where production of oil and gas occurs without incurring exploration costs such as the purchase of producing properties, exploration costs incurred by others are reflected in the cost of the leasehold. Respondent's narrow reading of the terms "mining process" or "mining" to include only extraction or production and to exclude the other phases of the exploration and production cycle, namely exploration, is not *404 supported by Cannelton Sewer Pipe Co. 16 Furthermore, respondent's contention that exploration falls outside of the mining process is not supported by his own regulations.
*190
In the regulation under
*192
The reference in the regulations to IDC is equally instructive. But for the option provided in
The exploration overhead at issue was incurred by virtue of all of petitioner's exploration activities, which were conducted upon probes and plays, geographic areas in which petitioner was interested but had not acquired a mineral interest, as well as on petitioner's nonproducing and, to a limited extent, producing properties. We have already concluded that it is improper to attribute direct expenses of probes, plays, or nonproducing properties (whether abandoned during the year or not) to petitioner's producing properties. Similarly, we think it is improper to allocate all indirect Exploration and Production organization expenditures to*194 producing properties. Consistent with cost accounting *406 principles, all of petitioner's direct exploration and production activities bore overhead costs or derived benefit from those costs. Petitioner's exploration and production activities were conducted not only on the geographic areas identified as the cost objective by
To this point*195 we have been concerned with questions of whether certain expenditures are directly or indirectly attributable to petitioner's Exploration and Production organization or to the producing properties within the Exploration and Production organization (and, ultimately, for WPT purposes, to barrels of oil). Only when expenditures are attributable to more than one activity or property, does the issue of the proper allocation of such indirect expenses arise. We must now consider the proper method by which indirect expenditures must be allocated for purposes of the NIL.
Expenditures which may be attributable both to the mineral property upon which depletion is claimed and to other activities shall be properly apportioned to the mineral property and to such other activities. Furthermore, where a taxpayer has more than one mineral property, deductions which are not directly attributable to a specific mineral property shall be properly apportioned among the several properties. * * * [Emphasis added.]
The parties have stipulated that the various indirect expenses incurred by petitioner must be grouped in homogeneous *407 *196 pools, each of which may be allocated on separate, rational bases. See C. Horngren & G. Foster, Cost Accounting, A Managerial Emphasis 445-446 (6th ed. 1987). The choice of the methods of allocating costs (or allocation bases) should be made with reference to the purpose to be served by the cost allocation. C. Horngren & G. Foster, supra at 448. 18 The allocation bases selected should reflect, to the extent possible, the beneficial or causal relationship between the cost objective and the indirect costs to be assigned. To this end the parties have stipulated to several methods of allocation depending upon the type of indirect expense that is being allocated. For example, the parties have agreed that corporate interest (including the contested interest) is to be allocated as overhead between petitioner's Products and Exploration and Production organizations based upon petitioner's relative capital expenditures. 19 The parties agree that State income and franchise taxes in the amount of $ 59,750,998 represent general corporate overhead, which must be allocated to petitioner's mining and nonmining activities based upon relative net income. The parties have also agreed to*197 allocate overhead between oil and gas production on producing properties based upon relative production treating 20,000 cubic feet as equal to one barrel of oil. 20
The parties stipulated that all indirect expenses incurred at or allocated to the divisions within the Exploration and Production organization must be allocated between producing and nonproducing properties using an allocation base they have identified as the modified direct expense method of allocation. 21 The parties have also*198 agreed that certain *408 general corporate overhead expenses must be allocated, using the same modified direct expense method of allocation. The precise question before us now is whether additional items must be included in the stipulated modified direct expense allocation in those instances where the parties have stipulated that it is to be used.
Petitioner contends that IDC*199 (including dry hole costs) totaling $ 614,217,253 should not be included as direct expenses in the stipulated modified direct expense allocation base. Respondent contends that those amounts must be included as direct expenses under the modified direct expense method to properly allocate overhead and other indirect expenses. Petitioner also contends that WPT is properly included as a direct expense under the stipulated modified direct expense allocation base; respondent contends to the contrary. Further, respondent contends that current G&G expenditures must be included in the stipulated allocation base to assure that overhead is properly allocated.
Neither
Although we look to cost accounting principles for guidance in deciding whether an allocation method results in costs being "properly apportioned," methods of allocation *409 are not accounting methods.
While we*201 recognize that the allocation methods here in question fall within the accounting arena, they are not analogous to the usual interperiod accounting problems with which the courts are usually concerned. Thus, changing allocation methods from year to year will not, of itself result in confusion or improper omissions of items of income. What is done in one year will not necessarily affect what is done in the following year. Indeed, within the requirement that expenses be "fairly apportioned," it may well be that periodical changing of allocation methods may be mandated because of altered conditions. Consistency of treatment over the years thus does not weigh heavily in the balance. * * * [
The leeway inherent in the term "properly apportioned" recognizes that more than one method may be acceptable for cost accounting purposes. The question of whether a given method of allocation properly apportions indirect expenses for purposes of the NIL is a factual question. 22 This factual inquiry must be contrasted with the legal issue of what items are properly deducted to arrive at taxable income from the property (i.e., *202 whether a given expense may be attributed, directly or indirectly, to producing properties). The most that can be required of a taxpayer to satisfy its burden of proof is "that the allocation method which it advocates produces a fairer apportionment for its circumstances than the allocation method advocated by respondent."
a. Inclusion of IDC in Allocation Base
Respondent contends that including IDC (which includes dry hole costs) totaling $ 614,217,252 in the allocation base for allocating overhead between producing and nonproducing properties results in a fairer allocation of those costs. Respondent agrees that if IDC is included in the allocation *410 base for allocating overhead*203 between producing and nonproducing properties, the IDC should also be included in the allocation base for allocating overhead between petitioner's Product and Exploration and Production organizations. Petitioner raises several objections to the inclusion of IDC in these allocation bases, which we will now examine.
Petitioner contends that the parties stipulated that the allocation base to be used was a modified direct expense method and that, because IDC is a cost that is capital in nature, it cannot properly be included. IDC costs are indeed capital in nature. But for the option to claim IDC as a current deduction under
Petitioner's experts all stated in conclusory terms that because IDC is a capital cost, it would be improper to include it with expenses in the allocation base. Dr. Koester stated that the stipulated modified direct expense method was intended to be the measure of relative operating activity, and that it was important not to mix operating expenditures with capital expenditures. If we accept his focus on operating activity to mean only petitioner's production efforts, it seems to contradict petitioner's repeated claim that all of the phases of the exploration and production cycle, exploration, development, and production, constitute a single activity. If we take operating activity to mean all of petitioner's efforts throughout the exploration and production cycle, it is possible that use of only direct currently deductible costs does not achieve the allocation goal. The primary direct costs of exploration (G&G) and development (IDC) are capital in nature, whereas the primary costs of the production phase are currently deductible. All of the exploration and production phases*205 incur overhead or derive benefit from overhead expenditures. If the inclusion *411 of IDC better reflects the relationship between the entire exploration and production activity of petitioner with respect to a property, then it should be included in the allocation base. We are also not persuaded by the distinction petitioner's other experts draw between IDC as a capital cost and the remaining agreed expenses.
The label used by the parties for their allocation base is not relevant. The label applied to a given method is merely descriptive. The question of whether IDC is properly included in "direct expenses" was raised as an issue by respondent in this case. Therefore, petitioner cannot argue that the stipulated term "expense" necessarily excludes capital costs. 23
*206 Petitioner also argues that the inclusion of IDC in the allocation base would distort the allocation of overhead. Petitioner argues that IDC on specific properties varies widely from year to year, causing the allocation of overhead to "shift wildly" among properties. More to the point, including IDC would increase the overhead allocated to properties being drilled (nonproducing properties) as opposed to developed (producing) properties. Petitioner complains that the increased allocation of overhead to nonproducing properties would cause those amounts to be "lost forever for purposes of the NIL."
It seems fundamental that if the allocation base selected results in significant distortion in the assignment of overhead, then the method should be modified or another method selected. Petitioner argues that the distortion that would be caused by the inclusion of IDC in the stipulated method justifies its exclusion. We are not convinced that undue distortion exists in the year before us by including IDC in the allocation base. To illustrate its claim, petitioner offers a hypothetical in which the taxpayer owned three mineral properties, two producing properties (property A and property*207 B) and one nonproducing property (property C), which the taxpayer found to contain substantial reserves of oil and gas. During the year, the taxpayer incurred $ 100 of operating expenses on each of properties A and B and *412 incurred $ 800 of IDC on property C. During the year, the taxpayer also incurred $ 80 of general corporate overhead which is to be "properly apportioned" under
The hypothetical offered by petitioner produces dramatic results. But even if the allocation resulting from petitioner's hypothetical demonstrates distortion sufficient to warrant excluding IDC, it has no relation whatsoever to petitioner's actual circumstances during the taxable period before us. Based upon the stipulations of the parties, by including IDC (which includes dry hole costs) in the allocation base, 69.4 percent of allocable overhead would be assigned to producing properties and 30.6 percent would be assigned to nonproducing*208 properties. By contrast, if IDC were excluded from the allocation base, 98.2 percent of allocable overhead would be assigned to producing properties and only 1.8 percent would be assigned to nonproducing properties.
Petitioner's complaint that including IDC in the allocation base would cause overhead to be lost forever is unconvincing. Clearly any adjustment to the allocation base that causes more overhead could be allocated to nonproducing properties would mean less overhead could be deducted in calculating the taxable income from producing properties. Consequently, petitioner's taxable income from the property and the NIL would be larger for purposes of percentage depletion and WPT. Under
Petitioner also argues that respondent's position is inconsistent with one of his published rulings and his treatment*209 of other taxpayers. In a published ruling, respondent has announced his position that, for purposes of allocating overhead for WPT NIL purposes, liability for WPT may not *413 be included in a direct expense allocation base.
Petitioner's argument that respondent has taken different positions with respect to the inclusion of IDC in the allocation base with different taxpayers is unpersuasive. In fairness to petitioner, we point out that it is not arguing that respondent always must take consistent positions with respect to similarly situated taxpayers. "It has long been the position of this Court that our responsibility is to apply the law to the facts of the case before us and determine the tax liability of the parties before us; how the Commissioner may have treated other taxpayers has generally been considered irrelevant in making that determination."
Respondent has demonstrated that, as to petitioner, incurring IDC is causally 24 or beneficially tied to incurring overhead expenses. IDC does not simply happen. The design, approval, implementation, and analysis of its drilling program involve all of the management and support services of petitioner, represented by the overhead costs to be allocated. Significant organization effort bears upon incurring IDC. Considerable analysis is required to select the site and prepare the drilling plan for wells. The preparation and approval of budgets calling for the expenditure of over one-half billion dollars in IDC requires efforts*212 at every level of petitioner's organization. Accumulating and compiling records of actual expenditures in a useable manner requires substantial accounting efforts. Although most of petitioner's drilling is performed by outside contractors, petitioner has personnel at each drilling rig to assure that the drilling contractor is following the drilling plan. As wells near the targeted depth, petitioner's geologists are present to analyze drill cuttings. Petitioner also purchases some materials used in the drilling process, such as drilling fluids and drill bits, to take advantage of large volume discounts available to it. Petitioner maintains a small inventory of tubular goods used in drilling and completing wells. Overhead costs for procurement, maintenance, and record keeping are necessary even for modest inventories.
*213 The facts establish that petitioner expends considerable efforts and resources in addition to those represented by direct expenditures identifiable as IDC. Those efforts and resources are reflected as overhead costs. The premise for the direct expense method of allocating overhead is that additional overhead burden is tied to the expenditure of additional direct expenses. For example, assume a taxpayer with only two properties, each with one producing well, one of which during the year produced at its expected rate with *415 only normal operating expenses, and the other requiring substantial expenditures for well reconditioning and recompletion, in addition to normal operating expenses. A greater portion of overhead expenditures should be allocated to the property with the troublesome well. To the extent that the direct expense allocation base reflects that disparity in the relationship between each property and the overhead theoretically attributable thereto, its use results in a proper apportionment.
Viewing petitioner's exploration and production efforts as a single activity, as petitioner insists we must, it is inappropriate to exclude from an allocation base a substantial*214 class of expenditure that, if the direct expense or direct cost method is sound, causes increased overhead. Petitioner's method narrowly considers only expenditures incurred in the production phase to reflect the overhead created by all of the activities on a given property. Direct expenditures incurred in the development phase (IDC) provide an equally sound basis for allocation of overhead. The opinion of respondent's expert, Dr. Deakin, confirms our conclusion. He concluded that the inclusion of IDC in the allocation base would aid in the achievement of a fair and equitable allocation of overhead.
Petitioner points out, correctly we think, that an allocation base is only a convenient method of linking the pool of overhead to the cost objective, and the allocation base need not include as factors every conceivable basis for a link between the two. An ideal allocation base for every circumstance probably does not exist, or is prohibitively expensive to implement. But here the link between IDC and overhead is apparent and petitioner has offered no evidence regarding the incremental cost of including it in the allocation base. Therefore, we are satisfied that including IDC in*215 the allocation base for allocating overhead between producing and nonproducing properties results in a fairer apportionment. 25
*216 *416 b. Inclusion of WPT in Allocation Base
Respondent points to nothing in the Windfall Profit Tax Act nor the legislative history indicating that WPT should not form a component of an allocation base in calculating taxable income from the property. *217 Nevertheless, he concludes that "There can be no doubt Congress did not want the WPT to influence the computation of the WPT." From this, respondent argues that WPT cannot be included in a direct expense allocation base even though he recognizes that allocations are simply necessary and imperfect substitutes for a direct assignment of costs which benefit more than one activity or property. 27 As support for his contention, respondent refers us to the requirement of
*218 We point out that using depletion (or WPT) in an allocation base to calculate taxable income from the property would cause more overhead to be allocated to producing *417 properties, thereby reducing taxable income from the property. Consequently, a taxpayer concerned only with obtaining the largest deduction for percentage depletion would not argue that depletion should be included in an allocation base because to do so would reduce the allowable deduction under the depletion NIL. Only since the enactment of the Windfall Profit Tax Act is it advantageous for certain taxpayers, including petitioner, to seek the lowest taxable income from the property because it serves to reduce the WPT liability due to the operation of the WPT NIL. It is thus no surprise that no taxpayer has argued that depletion should properly be included in a direct expense allocation base. In any event, that the inclusion of depletion (or WPT) in an allocation base for determining taxable income from the property has never been at issue before in no way suggests congressional intent. Quite simply, although there may be other reasons for excluding it, there is nothing in the Code nor the legislative history*219 of the Windfall Profit Tax Act specifying the methods to be used to allocate overhead or precluding the use of a taxpayer's WPT liability in an allocation base used in calculating taxable income from the property. The regulations promulgated by respondent under
Respondent next contends that WPT should be excluded from the allocation base at issue because it does not reflect a causal relationship between the overhead to be allocated and the producing property. His contention is grounded upon the claim that WPT should be included in the allocation formula only if the overhead on or other indirect expenses incurred with respect to the property rise in relation to the WPT liability incurred. Because respondent concludes that overhead does not rise in tandem with WPT liability (he actually claims they are inversely related), WPT should be excluded from the allocation base. Respondent's position is confirmed by the opinion of his expert witness, Dr. Deakin. However, respondent offered no evidence regarding *220 the behavior of petitioner's overhead and other indirect costs in response to WPT liability.
*418 We are convinced that there is a relationship between the WPT liability and the overhead incurred by petitioner. The enactment of the Windfall Profit Tax Act undoubtedly caused petitioner to incur increased administrative overhead. Petitioner was required to prepare and maintain substantial records relating to its liability as a producer; petitioner was required to file certifications, compute the WPT, and prepare and file quarterly WPT returns for over $ 750 million of WPT deposited by petitioner. 28 Particularly in 1980, the first year for which the WPT was effective, petitioner undoubtedly incurred costs in familiarizing itself with the requirements of the new Windfall Profit Tax Act, training employees, and setting up a system to comply with the new law. Because there is a causal connection between the WPT liability and the incidence of overhead, the WPT is correctly included in a direct expense allocation base.
*221 We are not persuaded by respondent's contention that the WPT should be excluded because the overhead it causes or creates does not increase as the WPT increases nor is the overhead theoretically allocable to each property based upon its WPT liability. As noted earlier, allocations are imperfect substitutes for a direct assignment of costs. In most cases, the causal relationship between the costs incurred and the overhead generated is not perfectly linear. However, imperfections in the causal relationship between the costs included in the allocation base and the overhead generated do not necessarily destroy the underlying validity of the allocation base. Other costs included in the stipulated allocation base do not appear to exhibit a clear linear or proportional relationship with overhead; e.g., severance taxes, property taxes, and cost of utilities as part of direct lease expense. We conclude that including the WPT in the stipulated allocation base results in a fairer, yet still imperfect, apportionment of overhead. A still better apportionment of overhead could be attained if the overhead attributable to petitioner's WPT liability could be segregated *419 and allocated*222 to producing properties on some appropriate basis. However, the parties agreed to aggregate all overhead and allocate it between producing and nonproducing properties using the stipulated method. We are reluctant to substitute a different method wherever we may simply conclude it is theoretically better than the one selected by the parties.
There are practical difficulties in using the WPT in an allocation base used to calculate WPT. Unless some substitute is used for the actual WPT liability as restricted by the 90-percent NIL, the determination of the appropriate amount of WPT to be used in the allocation base will require the use of simultaneous equations. The substitutes suggested by petitioner, the WPT liability computed without reference to the NIL or the net tax paid (the amount of WPT actually deposited during 1980), will always exceed the actual WPT liability taking into account the NIL whenever the NIL is triggered. Consequently, the use of the substitute methods will cause excessive amounts of overhead to be allocated to producing properties. Although in some instances the difference*223 resulting from use of one of the substitutes rather than actual WPT liability will be immaterial, in others it will be clearly material and distortive. Although the substitutes are easy to use, they will always result in a less than ideal allocation. Therefore, calculation of the WPT to be used in the allocation base should be the actual WPT liability computed with reference to the NIL, thus requiring the use of simultaneous equations.
Computations requiring the use of simultaneous equations are required elsewhere under Federal tax laws. They are required for a determination of the correct estate tax liability when property left to charity or to a surviving spouse is burdened by the payment of estate taxes. See
Simultaneous equations can be solved using either the trial and substitution method or the algebraic method. *225 Interrelated Computations for Estate and Gift Tax, I.R.S. Publication 904 (Rev. May 1985). Under either method ascertaining the solutions to simultaneous equations quickly becomes tedious as more variables are added. However, a computer program may be devised so that the computation need not be performed by hand. Petitioner's NIL computation is already computerized and it has the capability of performing the necessary calculations. 29 A great deal of trial time was devoted to the applicability of petitioner's computer. In light of petitioner's willingness to perform the necessary calculations, we cannot accept respondent's assertion that any benefits, in terms of improved matching of overhead to the cost objectives, derived from including the WPT in the allocation base, is outweighed by the costs of performing the allocation. We are mindful, however, that a method of allocation is chosen not only because it provides a sound matching of overhead to the cost objectives, but *421 also because the clerical costs and effort necessary to implement the allocation base are not excessive.
*226 c. Inclusion of G&G Expenditures in Allocation Base
In light of our holding that petitioner's probes and plays must be viewed as cost centers to which direct costs are identifiable, they also generate overhead. This conclusion becomes acutely apparent when we consider that a substantial part of petitioner's direct exploration efforts reflected in G&G costs are made with respect to probes and plays. Surely it is those direct efforts which caused or benefited from exploration-department overhead expenses totaling almost $ 54 million. However, most of the direct costs made with respect to probes and plays are G&G, which must be held in suspense until capitalized upon the acquisition of a mineral interest or abandonment. Consequently, the stipulated modified direct expense method fails to allocate overhead to probes and plays. If the direct expense method stipulated by the parties (and modified by our holdings with respect to the inclusion of IDC and WPT) is used without further modification, it will sidestep our holding that overhead costs must be attributed in part to probes and plays under consideration during the year. Therefore, we conclude that the stipulated direct expense*227 allocation base must be changed in order to properly allocate overhead between producing and nonproducing properties and probes and plays. Respondent argues that the stipulated method must include G&G costs incurred during the taxable period in issue with respect to probes and plays. G&G costs meet the inquiry necessary for inclusion in an allocation base; there is a readily established relationship between these costs and overhead. The exploration phase of petitioner's exploration and production cycle requires the efforts of geologists, geophysicists, and other personnel. Exploration personnel work together to collect and analyze information concerning the probability of locating commercially productive reserves of oil and gas. These efforts are directly reflected in G&G expenditures and indirectly in overhead. Consequently, we conclude that current G&G costs should be included in the stipulated allocation base. We point out that only current G&G expenditures reflect current overhead *422 costs. G&G costs incurred in prior years on properties that are deemed worthless and deducted for income tax purposes currently do not reflect current overhead activity, but such activity*228 of prior periods.
ConclusionWhen Congress enacted the 90-percent NIL on the WPT, it borrowed the concept of "taxable income from the property" from the 50-percent NIL on percentage depletion under
Respondent is, of course, empowered*229 to amend the regulations under
Decision will be entered under Rule 155.
Footnotes
*. Supplemental Opinion, 90 T.C. 747 (1988).↩
1. Unless otherwise noted, all section references are to the Internal Revenue Code of 1954 as amended and in effect during the taxable years in issue.↩
2. Taxable crude oil is defined as all domestic crude oil other than exempt oil.
Sec. 4991(a) . Exempt oil now includes crude oil from a qualified governmental or charitable interest, exempt Indian and Alaskan oil, exempt front-end oil, exempt royalty oil, and exempt stripper well oil.Sec. 4991(b)↩ .3. The proper taxable period for determination of a deficiency in windfall profit tax is a calendar year.
Page v. Commissioner, 86 T.C. 1">86 T.C. 1↩ (1986). Consequently, only the Commissioner's alternative deficiency of $ 241,810,176.17 determined in the notice of deficiency mailed Feb. 17, 1984, is at issue.4. Effective Jan. 1, 1975,
sec. 613A severely restricted the ability of an integrated oil company such as petitioner to claim percentage depletion. Undersec. 613A , an integrated oil company may claim percentage depletion only with respect to regulated and fixed contract natural gas or natural gas from geopressurized brine; it may not claim percentage depletion with respect to any crude oil production.Sec. 613(b) . However, the benefits of percentage depletion remain available to independent producers and royalty owners.Sec. 613A(c) . Taxpayers that remain eligible to claim percentage depletion are subject to a separate 65 percent NIL on the allowable deduction for percentage depletion.Sec. 613A(d)(2)↩ .5. See
General Portland Cement Co. v. United States, 628 F.2d 321">628 F.2d 321 , 343-344 (5th Cir. 1980), cert. denied450 U.S. 983">450 U.S. 983 (1981);Ideal Basic Industries, Inc. v. Commissioner, 82 T.C. 352">82 T.C. 352 , 400-402↩ (1984).6. The term "gross income from the property" is defined in
sec. 613(c) . Seesecs. 1.613-3 ,1.613-4, Income Tax Regs.↩ The parties have stipulated that the correct gross income from petitioner's mineral properties is not in dispute.7. As we pointed out some time ago in
Occidental Petroleum Corp. v. Commissioner, 55 T.C. 115">55 T.C. 115 , 123↩ (1970), "respondent has chosen to exercise his rule-making power in a very limited fashion. He has merely included in his regulations conclusory provisions that expenditures which are 'attributable' to a particular property must be deducted and that those which are not 'directly attributable * * * shall be fairly apportioned.'"8. However, respondent also refers to the following statement of Justice Holmes in
Weiss v. Wiener, 279 U.S. 333">279 U.S. 333 (1929):"The income tax laws do not profess to embody perfect economic theory. They ignore some things that either a theorist or a business man would take into account in determining the pecuniary condition of the taxpayer. [
279 U.S. at 335 .]"We do not think that the foregoing statement precludes an examination of economic or accounting theory or practice when the requirements for the tax accounting treatment are as unclear as those found in
sec. 1.613-5(a), Income Tax Regs.↩ In an actual conflict between accounting practice and the requirements of tax law, tax law would, of course, control.9. We recently noted that a purpose clause in a loan document was merely a recital of intent and not an operative provision.
Boseker v. Commissioner, T.C. Memo. 1986-353↩ . In contrast, using assets as security for indebtedness incurred in their acquisition has real legal consequences and is more likely to be the product of arm's-length agreement between the parties.10. Petitioner also incurred dry hole costs on its producing properties totaling $ 32,671,697. This amount is not at issue.↩
11. Although not relevant in the determination of taxable income from the property for NIL purposes, we point out that petitioner elects to use the successful-efforts method of accounting for financial reporting purposes. Under the successful-efforts method only the costs of successful exploratory wells are capitalized; costs of dry holes are expensed currently. In contrast, the full-cost method of accounting requires that the cost of all wells, whether dry or productive, be capitalized and recovered ratably through depletion. The full-cost method of accounting more fully recognizes the relationship between the cost of unsuccessful wells and productive wells urged by petitioner.↩
12. The term "property" is defined in the Code as "each separate interest owned by the taxpayer in each mineral deposit in each separate tract or parcel of land."
Sec. 614(a)↩ .13. Explicit in the NIL is the concept that taxable income will be calculated on a property-by-property basis. The NIL was enacted for percentage depletion purposes to prevent the reduction of nonmineral income with large depletion deductions; therefore, the property concept is arguably unnecessary. Congress could simply have limited the total deduction claimed for percentage depletion to 50 percent of the taxable income from mining operations. See
Consumers Natural Gas Co. v. Commissioner, 30 B.T.A. 1263">30 B.T.A. 1263 , 1264-1265 (1934), affd.78 F.2d 161">78 F.2d 161 (2d Cir. 1935), cert. denied296 U.S. 634">296 U.S. 634 (1935);Vinton Petroleum Co. v. Commissioner, 28 B.T.A. 549">28 B.T.A. 549 (1933), affd.71 F.2d 420">71 F.2d 420 (5th Cir. 1934), cert. denied293 U.S. 601">293 U.S. 601↩ (1934). Nevertheless, Congress chose to devise the NIL to operate on each property. Moreover, the legislative purpose behind the WPT NIL, encouraging the continued production from marginal properties, clearly requires the determination of taxable income on a property-by-property basis.14. Although it is true that the WPT NIL applies to the net income from each barrel (
sec. 4988(b)(1) ), such net income is calculated by dividing the net income from the property determined undersec. 613(a) by the number of barrels from such property taken into account for the taxable year.Sec. 4988(b)(2)↩ . Therefore, the net income will be the same for each barrel from a given property. The uniformity of the net income attributable to each barrel of oil from a property contrasts with the windfall profit on any barrel, calculated without reference to the NIL, which will vary depending upon the applicable tier of each barrel. This phenomenon causes the so-called "automatic NIL benefit" referred to by petitioner throughout the pendency of this suit. See Statham & Keenun, "WPT Tier 1 Crude Subject to Built-in Excess Withholding," Oil & Gas Journal 125 (Oct. 20, 1980).15. An early version of the regulations regarding the computation of taxable income from the property required allocation of indirect expenses between the taxpayer's oil and gas activities and other activities such as "operating refineries and transportation lines." Sec. 23(m), art. 221, Regs. 74. Note that this distinction is consistent with
United States v. Cannelton Sewer Pipe Co., 364 U.S. 76">364 U.S. 76 (1960), and related mining cutoff cases. SeeCommissioner v. Portland Cement Co. of Utah, 450 U.S. 156">450 U.S. 156 (1981);United States v. Henderson Clay Products, 324 F.2d 7 (5th Cir. 1963) , cert. denied377 U.S. 917">377 U.S. 917 (1964);Ideal Basic Industries v. Commissioner, 82 T.C. 352↩ (1984) .16. An "integrated oil company" has been defined as a company engaging in all phases of the oil industry, including exploration, production, transportation, manufacturing and refining, and retailing. H. Williams & C. Meyers, Manual of Oil and Gas Terms 427 (5th ed. 1981). A miner that engages in exploration activities, as well as simple extraction of known reserves is not an integrated miner. Petitioner, by virtue of its Exploration and Production and Products organizations, may be viewed as an integrated oil company; however, its Exploration and Production organization, standing alone, is not an integrated oil company.
The Supreme Court in
United States v. Cannelton Sewer Pipe Co., 364 U.S. 76 (1960) , was careful to classify the taxpayer as an "integrated miner-manufacturer" with respect to the issue of when the mining process ends.364 U.S. at 86-87 . In the Code an integrated oil company is defined as one that engages in selling or refining oil and gas.Sec. 4995(b)(3)↩ .17. Prior to 1972, the regulations referred to deductions "which are attributable to the mineral property, including allowable deductions attributable to ordinary treatment processes" or similar language. See
T.D. 6836 ,2 C.B. 182">1965-2 C.B. 182 , 184;T.D. 6446, 1 C.B. 208">1960-1 C.B. 208 , 236; sec. 23(m), art. 221, Regs. 77. The last quoted clause makes provision for deductions related to the permissible mining processes found insec. 613(c)(2) and(4) . Seesec. 1.613-4(f)(2)-(6), Income Tax Regs. In 1972 the vague term "mining process" was inexplicably substituted for the above-quoted language.T.D. 7170, 1 C.B. 191">1972-1 C.B. 191↩ .18. The choice of theoretically more precise but complex, allocations methods must also be tempered by the effort and cost required to make such allocations.↩
19. In light of our holding with regard to the Belridge interest, some portion of total corporate interest must be allocated to petitioner's subsidiary investment or investments.↩
20. The selection of the 20,000-to-1 ratio for allocating overhead between gas and oil production appears to have been made by the parties to satisfy the requirement of
sec. 613A(c)↩ 7(C).21. We have held above that Exploration department overhead in the amount of $ 53,965,802, Land department overhead in the amount of $ 8,800,296, Research and Development Expenses in the amount of $ 41,600,643, Miscellaneous Regional expenses in the amount of $ 4,139,034, general corporate overhead allocated to the Exploration and Production organization, regional overhead, and division overhead must be allocated, in part, to probes or plays on which petitioner conducted exploration and production activities during the year in order to properly determine only the income attributable to producing properties upon which depletion is claimed.↩
22. On petitioner's motion we ruled that the statutory notice of deficiency was arbitrary and that its presumption of correctness was destroyed. Consequently, the burden of going forward was shifted to respondent with respect to factual issues.↩
23. The use of the word "modified" in the description of this method refers only to the agreement of the parties to exclude certain items, such as fuel expense and depreciation on refineries, in order to reduce the amount of overhead allocated to petitioner's Products organization.↩
24. When discussing the proper elements of the allocation base respondent has frequently used the terminology "effort related." For example, respondent contends that incurring IDC in contrast to incurring other capital costs, is "effort related." We are satisfied that this term is used merely to express the cause and effect relationship of a direct cost to overhead.↩
25. It is interesting that early versions of the regulations interpreting the term "taxable income from the property" required that indirect expenses that were attributable to a taxpayer's oil and gas activities and its other activities must be allocated based upon relative direct "operating expenses [and] development expenses (if the taxpayer has elected to deduct development expenses). Sec. 23(m), art. 221, Regs. 74 (emphasis added). It is speculation on our part but the requirement that indirect expenses be allocated based upon relative direct expenses (including IDC) may have been dropped in later versions of the regulations because of the recognition that the relative direct expense method was not necessarily the appropriate allocation base for all types of indirect expenses. Respondent later abandoned efforts to prescribe specific allocation bases for purposes of
sec. 613 . SeeT.D. 6446 ,1 C.B. 208">1960-1 C.B. 208↩ .26. WPT remains deductible in the calculation of taxable income from the property for percentage depletion NIL purposes. See H. Rept. 96-304,
3 C.B. 81">1980-3 C.B. 81↩ , 87.27. Respondent's position on this issue was announced publicly in
Rev. Rul. 85-79, 1 C.B. 337">1985-1 C.B. 337↩ .28. Under the Windfall Profit Tax Act petitioner is required to undertake substantial reporting, withholding, and depository duties in its role as first purchaser of domestic crude apart from its WPT liability. We agree with respondent that there is no causal connection between the overhead costs attributable to the withholding duties and petitioner's WPT liability. In an ideal allocation of overhead, these costs would likely be allocated solely to petitioner's Product organization.↩
29. For the first time on brief, respondent alleges that the simultaneous equations required by including the WPT in the allocation base for allocating overhead would not yield a single solution, but only a range of solutions. Respondent offered no admissible evidence on this point and we decline to make any finding with respect to this contention.↩