1987 U.S. Tax Ct. LEXIS 123 | Tax Ct. | 1987
Lead Opinion
The Commissioner determined deficiencies in petitioner’s windfall profit tax under section 4986
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 section 4986 for the entire taxable year ended December 31, 1980, in the amount of $241,810,176.17.
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 section 1.613-5(a), Income Tax Regs., for purposes of the windfall profit tax net income limitation. We must decide (1) whether net corporate interest of $145,585,641 incurred in the acquisition of Belridge Oil Co. by a subsidiary of petitioner should be treated as general corporate overhead and allocated, in part, to petitioner’s exploration and production activity; (2) whether petitioner correctly attributed several overhead expenses, indirect exploration expenses, and abandonment losses to its producing and nonproducing properties; (3) whether intangible drilling and development costs (IDC) and windfall profit tax (WPT) should be included as direct expenses when the relative direct expense method is used to allocate overhead and indirect expenses to determine taxable income from the property.
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 through development and production to purchasing, refining, 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 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 should be developed further. When the exploration department decided, with the input of the land and production departments, 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 providéd funds for the drilling of the wildcat well or wells. The production department drilled the wildcat 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, 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 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 wfre 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 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 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.
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 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 petitioner. Further, neither lo.an 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 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, $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 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 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 3to Kernridge in excess of the costs of acquiring Belridge viere 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 amounts in computing taxable income from the property for purposes of the deduction for percentage depletion under section 613(a) on its income tax returns for the taxable years 1975 through 1979, was adopted in the 1950’s or 1960’s and was used consistently until 1980. For the taxable years 1975 through 1979, petitioner did not take into account any indirect expenditures or overhead above the division level.
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 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 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 section 4988(b) in the amount of $141,794,896. This amount, along with a claimed overpayment of WPT by Kernridge in the amount of $38,206,653, were claimed on Fprm 1120 as a credit against petitioner’s 1980 Federal income tax liability. Although Kernridge was included in the consolidated group for income tax purposes, it was nrot consolidated for purposes of the windfall profit tax.
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. 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. 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 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 lfevel 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 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 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 and Production organization at the first level of allocation are to be combined with indirect Exploration and Production organization expenses identified a§ 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 in the stipulated modified direct expense allocation base. They have stipulated that the 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 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, 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), 1980-3 C.B. 81, 91; S. Rept. 96-394 (1979), 1980-3 C.B. 131, 142. Consequently, Congress enacted the Crude Oil Windfall Profit Tax Act of 1980, Pub. L. 96-223, 94 Stat. 229, which imposes a temporary excise, or severance, tax on certain crude oil produced in the United States. See sec. 4986. Under the Windfall Profit Tax Act the applicable tax rate is applied to the windfall profit per barrel. The windfall profit per barrel is generally calculated by subtracting the applicable adjusted base price, and a severance tax adjustment, from the removal price. Sec. 4988(a). All taxable barrels of crude
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.f,227, 239, 254, as a limitation on the allowance for discovery depletion, the statutory precursor of percentage depletion. 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 North Carolina Granite Corp. v. Commissioner, 43 T.C. 149, 165-166 (1964). When the 1954 Code was enacted, the term “net income” was changed to “taxable income” in new section 613. No change in substance was intended. S. Rept. 1622, 83d Cong., 2d Sess. 330 (1954); North Carolina Granite Corp. v. Commissioner, supra. The purpose for limiting the deduction for percentage depletion to a portion of the net income from the property is to ensure that the depletion deduction is not used to offset the taxpayer’s income from a separate and distinct line of business. S. Rept. 275, 67th Cong., 1st Sess. (1921), reprinted in 1939-1 C.B. (Part 2) 181, 191. The purpose of the NIL under the Windfall Profit Tax Act, however, is to assure continued production from high cost properties, which otherwise might be shut-in because of the WPT burden. Staff of the Joint Comm, on Taxation, 96th Cong., 1st Sess., The Design of a Windfall Profit Tax, at 29 (Comm. Print 1979).
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 section 4988(b).
Current regulations under section 613 provide as follows:
(a) General rule. The term “taxable income from the property (computed without allowance for depletion)”, as used in section 613 and this part, means “gross income from the property” as defined in section 613(c) and §§1.613-3 and 1.613-4, less all allowable deductions (excluding any deduction for depletion) which are attributable to mining processes, including mining transportation, with respect to which depletion is claimed. These deductible items include operating expenses, certain selling expenses, administrative and financial overhead, depreciation, taxes deductible under section 162 or 164, losses sustained, intangible drilling and development costs, exploration and development expenditures, etc. See paragraph (c) of this section for special rules relating to discounts and to certain of these deductible items. 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. In determining the taxpayer’s taxable income from the property, the amount of any particular item to be taken into account shall be determined in accordance with the principles set forth in paragraphs (d)(2) and (3) of §1.613-4. [Sec. 1.613-5, Income Tax Regs.]
Following the enactment of section 613A, Tax Reduction Act of 1975, Pub. L. 94-12, sec. 501, 89 Stat. 26, 47, petitioner’s Federal income tax deduction for percentage depletion decreased significantly.
Issue 1. Interest Incurred in Belridge Acquisition
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 section 1.613-5(a), Income Tax Regs. Respondent contends primarily that such interest is a direct expense of the acquisition of Belridge and that, in any event, it cannot be treated as an indirect expense of petitioner’s Exploration and Production organization. The parties have stipulated that net interest
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 section 613(a) provide in part, that “taxable income from the property” means “gross income from the property,”
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, 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 stkted 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 section 613(a). St. Marys Oil & Gas Co. v. Commissioner, 42 B.T.A. 270 (1940); Mirabel Quicksilver Co. v. Commissioner, 41 B.T.A. 401 (1940). Respondent’s concession of this point is demonstrated by his agreement that at least $74,355,000 of net interest expense constitutes general corporate overhead allocable between petitioner’s Products and Exploration and Production organizations, and, therefore, ultimately allocable, in part, to producing properties. However, the regulations do not assist us in analyzing the parties’ different interpretations of the term “attributable” used therein.
St. Marys Oil & Gas Co. v. Commissioner, supra, a case relied upon by respondent, does not compel the interpretation he seeks. In that case, the taxpayer borrowed money on its general credit and used the funds to purchase part of the property from which oil and gas was produced. Interpreting regulatory language substantially similar to section 1.613-5(a), Income Tax Regs., the Board of Tax Appeals held that the taxpayer’s general credit indebtedness was attributable to the taxpayer’s oil producing property. The Board considered dictionary definitions for the word “attribute,” “By definition, to attribute is to ‘ascribe (something) as due and belonging’ * * * ; ‘to impute; to assign; to consider as belonging to.’ ” 42 B.T.A. at 272. However, the Board was not faced with the question before us, i.e., whether interest expense is attributable to all of a taxpayer’s activities where the taxpayer was engaged in more than one activity. In St. Marys Oil & Gas Co. v. Commissioner, supra, the taxpayer had only one property, its oil and gas property, and one activity, the production of oil and gas from that property. In this respect, St. Marys Oil & Gas Co. v. Commissioner, supra, primarily stands for the proposition that interest is an allowable deduction for determining taxable income from the property. The parties have identified no cases that bear directly upon the issue before us.
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 interest expense to the purchase or carrying of tax-exempt obligations. Earl Drown Corp. v. Commissioner, 86 T.C. 217, 223 (1986); Indian Trail Trading Post, Inc. v. Commissioner, 60 T.C. 497, 500 (1973), affd. 503 F.2d 102 (6th Cir. 1974). The purpose to purchase or hold tax-exempt obligations can be found, and an allocable portion of the interest deduction disallowed, even where the use of the loan proceeds cannot be traced and assets other than the tax-exempt obligations Eire used to secure the indebtedness. Leslie v. Commissioner, 413 F.2d 636 (2d Cir. 1969), revg. 50 T.C. 11 (1968), followed in Bradford v. Commissioner, 60 T. C. 253 (1973). However, respondent has not demonstrated to our satisfaction that the purpose test implicit in the language of section 265(2) provides a test for determining the meaning of “attribute” in the regulations under section 613. Section 265(2) is designed to prevent a taxpayer from obtEiining a double tax benefit by deducting interest on borrowed funds, which enable the taxpayer to purchase or ceirry securities bearing tax-exempt interest. Denman v. Slayton, 282 U.S. 514, 515 (1931). The purpose of the regulations under section 613 is to provide guidelines for identifying those items of income and deduction which constitute taxable income from the property.
Inasmuch as section 613(a) requires that the items of income and deduction related to the individual properties upon which depletion is claimed be identified, the computation of “taxable income from the property” is a tax accounting procedure that draws upon anEilogous cost accounting principles. Tax accounting requirements will, of course, prevail over accepted financial or cost accounting principles. See Thor Power Tool Co. v. Commissioner, 439 U.S. 522 (1979). However, in this instance, neither the Code, nor the regulations, nor the case law provides any guidance for resolution of the question before us, how to interpret the word “attributable” in section 1.613-5(a), Income Tax Regs. Given the lack of' specific guidance in the Code and regulations, we hold that cost accounting principles may be relied upon to assist in interpreting the statute and regulations, Occidental Petroleum Corp. v. Commissioner, 55 T.C. at 125, and respondent concedes as much.
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 gimilar conclusion about the general conditions necessary ¿for specific financing to be associated with specific assets or activities. 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, 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 Occidental Petroleum Corp. v. Commissioner, supra, concluded that, while other methods are sometimes used for other accounting purposes, treating interest expense as an overhead item, as petitioner argues, is recognized by cost accounting authorities as appropriate.
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 section 861. Sections 861 to 863 provide rules for the treatment of gross income and taxable income from sources within and without the United States. Section 1.861-8, Income Tax Regs., “¡‘provides specific guidance for applying the cited Code sections by prescribing rules for the allocation and apportionment! of expenses, losses, and other deductions * * * of the taxpayer.” Sec. 1.861-8(a)(l), Income Tax Regs. With regard to the treatment of interest expense, these same regulations provide as follows:
(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 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 producing activities and properties of the taxpayer generate, have generated, or could reasonably have been expected to generate.
[Sec. 1.861-8(e)(2), Income Tax Regs.]
The regulations under section 861, therefore, generally treat interest expense as attributable to all of a taxpayer’s activities. Attribution of an item of interest expense solely to a specific activity or property is required only under the terms of the following exception:
(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 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.
[Sec. 1.861-8(e) (2)(iv), Income Tax Regs.]
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.” Nevertheless, they support the opinions of petitioner’s experts on the fungibility of interest 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 toga cost objective. He concludes that the contested interest meets cost accounting standards as a direct expense of the Belridge acquisition. In 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 section 613(a) and the regulations promulgated thereunder. In reaching this conclusion, we have carefully considered the testimony and reports of the accounting experts presented by the parties. We acknowledge that the experts reached opposing conclusions. However, we are convinced that petitioner’s method is an acceptable method under cost accounting principles. We also point out that the view of interest advocated by petitioner is less prone to manipulation by certain taxpayers. If all that is required for direct attribution of interest expense is that a given purpose be stated for a loan and some tracing of the funds be possible, we think taxpayers may be tempted to insert or omit recitals of purpose into loan documents
Issue 2. Seven Disputed Exploration and Production Organization Expenditures
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
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, 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.
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 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 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.
Section 613(a) allows a deduction for depletion based upon the gross income from the property.
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 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 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 section 613(a) and the regulations promulgated thereunder, calculating the taxable income from the producing properties.
In support of its argument that all unsuccessful efforts to produce oil or gas must be attributed to its 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 which cost depletion may be claimed. Louisiana Land & Exploration Co. v. Commissioner, 7 T.C. 507, 514-516 (1946), affd. on other issues 161 F.2d 842 (5th Cir. 1947). It is respondent’s published position that G&G costs incurred with respect to geographic areas identified as project areas and areas of interest prior to the acquisition of any mineral interest in those lands must be held in suspense pending a decision to acquire a mineral interest. Rev. Rui. 77-188, 1977-1 C.B. 76. The terms “probe” and “play” as used by petitioner to identify the phases of its exploration and production cycle appear to coincide with the terms “project areas” and “areas of interest” in respondent’s rulings. If a mineral interest or interests are subsequently acquired, those G&G costs are capitalized to that mineral interest or interests. If the G&G costs do not indicate the presence of oil or gas in sufficient quantities to justify further action and, therefore, no mineral interest is acquired, then the taxpayer is entitled to deduct the G&G costs held in suspense as a loss under section 165. For convenience we shall refer to these costs as abandoned G&G costs.
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 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 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 section 1.613-5(a), Income Tax Regs., is the producing property, we think it is improper, under section 613 and section 1.613-5(a), Income Tax Regs., to attribute to producing properties costs that are directly attributable to probes, plays, or nonproducing properties.
Provided a proper showing of abandonment has been made, G&G that has been capitalized to a mineral interest, along with capitalized leasehold costs, is deductible for income tax purposes as losses under section 165. Gulf Oil Corp. v. Commissioner, 87 T.C. 135 (1986) (“Worthless Properties”); Brountas v. Commissioner, 73 T.C. 491, 582-587 (1979), affd. on this issue and revd. in part 692 F.2d 152 (1st Cir. 1982), affd. on this issue and revd. in part sub nom. CRC Corp. v. Commissioner, 693 F.2d 281 (3d Cir. 1982). Petitioner claimed a deduction for lease bonuses on abandoned properties in the amount of $41,845,607 and abandoned capitalized G&G in the amount of $15,392,113. None of the abandonments relate to any of the properties retained by petitioner. Therefore, the costs relating to the abandonments may not be deducted in the calculation of taxable income from producing properties for NIL purposes. To do otherwise would permit petitioner to deduct expenses that are neither directly nor indirectly attributable to the cost objective mandated by section 613(a) and the regulations thereunder.
The arguments of the parties differ somewhat with respect to the proper treatment of the exploration department indirect 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? Rev. Rul. 83-105 Analyzed,” 60 J. Tax. 118 (Feb. 1984). The disputed exploration department indirect costs are not identifiable with specific mineral properties and include head office and regional expenses allocated to the exploration department at the division level, salaries and expenses of the division exploration manager and his immediate staff, office rent and supplies, sales and use taxes on items purchased by the exploration departments. In accordance with the stipulation of the parties, we assume that these costs are currently deductible for income tax purposes.
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 an “other activity” under section 1.613-5(a), Income Tax Regs. Consequently, respondent contends that these expenditures, even if otherwise deductible for income tax purposes, may not be considered in the calculation of taxable income from the property. We disagree.
In support of his contentions regarding exploration as being outside the meaning of “mining processes,” respondent relies upon United States v. Cannelton Sewer Pipe Co., 364 U.S. 76 (1960). The taxpayer in that case mined fine clay and shale and transported these raw mineral products to its plant where it processed and fabricated the raw materials into vitrified sewer pipe, flue lining, and related products. The taxpayer argued that its gross income from the property upon which its deduction for percentage depletion would be calculated was the price at which it sold its finished products, although the mined materials were marketable in their raw state. The Court reviewed the applicable statutory language and legislative history of percentage depletion and noted that gross income means the gross income from mining, which, in turn, includes, in the case of hard minerals, not only the extraction of ores or minerals from the ground, but also certain ordinary treatment processes normally applied to obtain commercially marketable mineral product. 364 U.S. at 81-84; see sec. 613(c). The Court pointed out that “none of the permissible processes destroy the physical or chemical identity of the minerals or permit them to be transformed into new products.” 364 U.S. at 85-86. The Court then concluded that “Congress intended to grant miners a depletion allowance based on the constructive income from the raw mineral product, if marketable in that form, and not on the value of the finished articles.” 364 U.S. at 86.
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. 364 U.S. at 89. If an integrated miner were allowed to calculate his “gross income from the property” based upon the sale of finished products rather than the raw mineral in its first marketable state, the parity between all miners would be destroyed. Respondent views the requirement that the deduction for percentage depletion be calculated in the same manner for integrated and nonintegrated miner as support for its conclusion that exploration activities fall outside the meaning of “mining process” and within the meaning of “other activities” under section 1.613-5(a), Income Tax Regs. While we certainly do not quarrel with the Supreme Court’s interpretation of legislative intent; we disagree with the conclusion that respondent draws therefrom. We view Cannelton Sewer Pipe Co. to be concerned solely with the question of when the mining process ends and not when the mining process may be considered to commence. We, therefore, interpret “other activities” to include nonmining activities such as petitioner’s Product organization or other distinct lines of business.
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 supported by Cannelton Sewer Pipe Co.
In the regulation under section 613, we find acknowledgement that costs from all phases of the exploration and production cycle that are otherwise deductible for income tax purposes are deductible, if attributable to the mineral property, in the calculation of taxable income from the property. The first sentence of section 1.613-5(a), Income Tax Regs., defines taxable income from the property as gross income from the property less “all allowable deductions * * * which are attributable to mining processes * * * with respect to which depletion is claimed.”
The reference in the regulations to IDC is equally instructive. But for the option provided in section 263(c), IDC would be capitalized and recoverable only through cost depletion. Gulf Oil Corp. v. Commissioner, 87 T.C. 324, 340 (1986); Standard Oil Co. (Indiana) v. Commissioner, 77 T.C. 349, 382 (1981); Sun Co. v. Commissioner, 1A T.C. 1481, 1507 (1980), affd. 677 F.2d 294 (3d Cir. 1982); Gates Rubber Co. v. Commissioner, 74 T.C. 1456, 1474 (1980), affd. per curiam 694 F.2d 648 (10th Cir. 1982); Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. 325, 344-345 (1977). If a taxpayer elects to claim a current deduction for IDC, the regulation under section 613 makes quite clear that the deduction shah be subtracted from gross income from the property to calculate taxable income from the property. Sec. 1.613-5(c)(2), Income Tax Regs. From this we conclude that “all allowable deductions” from all phases of the exploration and production cycle, excluding, of course, deductions attributable to activities beyond the permissible mining processes as dehneated in Cannelton and similar cases, are deductible for NIL purposes. Therefore, if petitioner’s contentions regarding the deductibihty of exploration overhead are borne out in a separate trial of income tax issues, those expenses will be deductible, at least in part, for depletion and WPT NIL purposes. This conclusion, however, does not resolve the question of whether the exploration overhead is entirely attributable to producing properties, as petitioner claims.
The exploration overhead at issue was incurred by virtue of ah 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 producing properties. Consistent with cost accounting 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 section 1.613-5(a), Income Tax Regs., but they were also conducted on nonproducing properties, probes, and plays. We conclude, therefore, that all overhead allocated to the Exploration and Production organization and all overhead incurred at the regional and division levels within petitioner’s Exploration and Production organization, including other exploration expenses in the amount of $53,965,802, must be allocated not only to petitioner’s producing and nonproducing properties, as stipulated by the parties, but also to any probes and plays under consideration during the taxable year. Similarly, land department expenses totaling $8,800,296, which respondent conceded on brief is allocable overhead, must be apportioned among petitioner’s producing and nonproducing properties, probes, and plays.
Issue 3. Allocation of Indirect Expenses
To this point 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. Section 1.613-5(a), Income Tax Regs., provides as follows:
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 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.
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.
Petitioner contends that IDC (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 section 613 nor the regulations prescribe a standard for apportionment. Occidental Petroleum Corp. v. Commissioner, 55 T.C. 115, 123 (1970). The regulations merely provide that, where indirect expenses must be allocated among more than one cost objective, they must be “properly apportioned.” The appropriate choice of allocation methods will depend upon the specific circumstances of the taxpayer. By their nature, allocations are imperfect substitutes for direct assignments of costs; however, it is necessary to allocate those costs that benefit more than one activity or property. This is not to say that certain methods may not be superior for a given purpose from a cost accounting perspective. It is recognized that, as the parties have stipulated, a taxpayer may resort to several different methods of allocation depending upon the various costs to be allocated and the objective of the allocation. Nevertheless, the methods selected “must at least be defensible within certain broadly defined cost accounting parameters.” Occidental Petroleum Corp. v. Commissioner, supra at 125.
Although we look to cost accounting principles for guidance in deciding whether an allocation method results in costs being “properly apportioned,” methods of allocation are not accounting methods. Occidental Petroleum Corp. v. Commissioner, supra at 123. Consequently, respondent has not asserted his authority under section 446 and cases reviewing that authority are, therefore, not in point. Occidental Petroleum Corp. v. Commissioner, supra. Furthermore, as we said in Occidental:
While we 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. * * * [55 T.C. at 123-124; fn. ref. omitted.]
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.
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 nonproduc-ing properties results in a fairer allocation of those costs. Respondent agrees that if IDC is included in the allocation base for allocating overhead 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 section 263(c), they would be required to be capitalized under section 263(a). Gulf Oil Corp. v. Commissioner, supra; Standard Oil Co. (Indiana) v. Commissioner, 77 T.C. at 382; Sun Co. v. Commissioner, supra, Gates Rubber Co. v. Commissioner, supra; Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. at 344-345. However, we do not think the classification of a given cost as capital or expense governs the inquiry here. The question is whether the inclusion of IDC with other items of expense results in a fairer allocation of overhead.
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 incur overhead or derive benefit from overhead expenditures. If the inclusion 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.
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 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 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 sec. 1.613-5(a), Income Tax Regs. If IDC were included with direct expenses the allocation base in this instance, property C would be allocated $64 of overhead (800/($100 + $100 + $800) X $80=$64), while properties A and B each would be allocated only $8 of overhead.
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 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 section 613 and the regulations, the cost objective is the taxpayer’s producing properties. Only those deductions directly or indirectly attributable to producing properties may be taken into account in the calculation of taxable income from the property. All other deductions are, indeed, “lost” for NIL purposes, but that is the result mandated by statute and the regulations.
Petitioner also argues that respondent’s position is inconsistent with one of his published rulings and his treatment 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 be included in a direct expense allocation base. Rev. Rul. 85-79, 1985-1 C.B. 337. According to respondent, given the fact that the WPT may not be deducted for WPT NIL purposes (sec. 4988(b)(3)(B)(ii)), including WPT in a direct expense allocation base would frustrate congressional intent that the WPT not influence the computation of taxable income for NIL purposes. Irrespective of the merits of this contention (see discussion, infra), we do not find it to be inconsistent with respondent’s position in this case regarding the inclusion of IDC in the allocation base. As petitioner correctly points out, productive well IDC, like WPT liability, may not be deducted in the calculation of taxable income from the property. Sec. 4988(b)(3)(B)(iii). Nevertheless, nonproductive IDC remains deductible, and productive IDC may be deducted ratably through the deduction for hypothetical cost depletion. Sec. 4988(b)(3)(C). Consequently, all IDC is taken into account in the calculation of taxable income from the property for WPT NIL purposes, albeit some in later years, and the rationale of Rev. Rul. 85-79, supra, is not applicable to IDC.
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.” Davis v. Commissioner, 65 T.C. 1014, 1022 (1976); but see Sirbo Holdings, Inc. v. Commissioner, 476 F.2d 981 (2d Cir. 1973), remanding 57 T.C. 530 (1972). Petitioner contends that, because respondent has taken the position that IDC must be excluded from the allocation base with respect to other taxpayers, that for petitioner to exclude IDC from the allocation base would result in a proper apportionment of overhead. Even if petitioner had convincingly established that respondent has taken inconsistent positions with respect to IDC, petitioner’s argument fails to resolve the dispute before us. That dispute remains to be whether the inclusion of IDC in a direct expense allocation base results in a fairer apportionment of overhead for this taxpayer for the particular taxable period before us.
Respondent has demonstrated that, as to petitioner, incurring IDC is causally
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 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 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 the allocation base for allocating overhead between producing and nonproducing properties results in a fairer apportionment.
b. Inclusion of WPT in Allocation Base
Section 4988(b)(3)(B)(ii) expressly prohibits the deduction of the WPT in the calculation of the NIL for WPT purposes.
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. 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.
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 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 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 section 613, likewise, do not specify any particular methods of allocating indirect costs, but require only that they be properly apportioned. Sec. 1.613-5(a), Income Tax Regs.
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 the behavior of petitioner’s overhead and other indirect costs in response to WPT liability.
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.
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 and allocated 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. Occidental Petroleum Corp. v. Commissioner, supra at 132.
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 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 secs. 2055(c), 2056(b)(4); sec. 20.2055-3, 20.2056(b)-4(c), Estate Tax Regs.; see also Estate of Baumberger v. Commissioner, 551 F.2d 90 (5th Cir. 1977), affg. an unpublished opinion of this Court. Similarly, the determination of the correct gift tax liability requires the use of simultaneous equations where the donee is required to pay the gift tax. When a self-employed person makes contributions to a defined contribution plan, there is an interaction between the person’s compensation (the base upon which the deduction for the contribution to the plan is computed) and the deduction itself, which may require the use of simultaneous equations. Under section 338, the interplay of the deemed sales price of the assets following a transfer of control of a corporation to achieve a step-up in tax basis for the corporation’s assets and recapture taxes requires complex simultaneous equations. See sec. 1.338-4T(h)(3), Answer 2, Temporary Income Tax Regs., 50 Fed. Reg. 16421 (Apr. 25, 1985); Joy & Hahn, “How to Compute Elective Formula Under Section 338 Where There is Recapture,” 64 J. Tax. 334, 335 (June 1986). The deductions for dividends received and percentage depletion are both subject to limitations based upon a percentage of the taxable income of the taxpayer. Secs. 246(b), 613A(d). The interplay of these two limitations may require the use of simultaneous equations. See Rev. Rul. 79-347, 1979-2 C.B. 122.
Simultaneous equations can be solved using either the trial and substitution method or the algebraic method. 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.
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 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 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 of prior periods.
Conclusion
When 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 section 613(a). The fundamental difference between the operation of the two limitations caused taxpayers, such as petitioner, with large potential WPT liabilities and limited allowable deductions for percentage depletion, to view the meaning of “taxable income from the property” in a new light. Petitioner modified its method of calculating taxable income from the property, which had been used with the apparent consent of respondent for decades. After the enactment of the WPT, for. the first time petitioner claimed overhead incurred above the division level and other indirect expenses as allowable deductions in the calculation of the taxable income from the property. We have decided the issues presented with respect to this petitioner for the taxable period in issue based upon the statutes and attendant legislative intent, the regulations, applicable case law, and, where appropriate, upon proper principles of cost accounting as we can best ascertain.
Respondent is, of course, empowered to amend the regulations under section 613(a). We recognize that the attempt to prescribe the proper calculation of taxable income from the property for all taxpayers in all circumstances would result in exceedingly complex regulations. We do not urge respondent to undertake such a task; nevertheless, further administrative interpretation appears particularly appropriate. See Helvering v. Wilshire Oil Co., 308 U.S. 90, 102-103 (1939); see also Occidental Petroleum Corp. v. Commissioner, 55 T.C. at 133.
Decision will be entered under Rule 155.
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.
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).
The proper taxable period for determination of a deficiency in windfall profit tax is a calendar year. Page v. Commissioner, 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.
Effective Jan. 1, 1975, sec. 613A severely restricted the ability of an integrated oil company such as petitioner to claim percentage depletion. Under sec. 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).
See General Portland Cement Co. v. United States, 628 F.2d 321, 343-344 (5th Cir. 1980), cert. denied 450 U.S. 983 (1981); Ideal Basic Industries, Inc. v. Commissioner, 82 T.C. 352, 400-402 (1984).
The term “gross income from the property” is defined in sec. 613(c). See secs. 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.
As we pointed out some time ago in Occidental Petroleum Corp. v. Commissioner, 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.’ ”
However, respondent also refers to the following statement of Justice Holmes in Weiss v. Wiener, 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.
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.
Petitioner also incurred dry hole costs on its producing properties totaling $32,671,697. This amount is not at issue.
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.
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).
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, 1264-1265 (1934), affd. 78 F.2d 161 (2d Cir. 1935), cert. denied 296 U.S. 634 (1935); Vinton Petroleum Co. v. Commissioner, 28 B.T.A. 549 (1933), affd. 71 F.2d 420 (5th Cir. 1934), cert. denied 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.
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 under sec. 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).
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 (1960), and related mining cutoff cases. See Commissioner v. Portland Cement Co. of Utah, 450 U.S. 156 (1981); United States v. Henderson Clay Products, 324 F.2d 7 (5th Cir. 1963), cert. denied 377 U.S. 917 (1964); Ideal Basic Industries v. Commissioner, 82 T.C. 352 (1984).
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).
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, 1965-2 C.B. 182, 184; T.D. 6446, 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 in sec. 613(c)(2) and (4). See sec. 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, 1972-1 C.B. 191.
The choice of theoretically more precise but complex, allocations methods must also be tempered by the effort and cost required to make such allocations.
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.
The selection of the 20,000-to-l 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).
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.
0n 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.
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.
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.
It is interesting that early versions of the regulations interpreting the terra “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 ed 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. See T.D. 6446, 1960-1 C.B. 208.
WPT remains deductible in the calculation of taxable income from the property for percentage depletion NIL purposes. See H. Rept. 96-304, 1980-3 C.B. 81, 87.
Respondent’s position on this issue was announced publicly in Rev. Rul. 85-79, 1985-1 C.B. 337.
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.
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.