Shell Oil Company v. Commissioner of Internal Revenue

952 F.2d 885, 117 Oil & Gas Rep. 599, 69 A.F.T.R.2d (RIA) 654, 1992 U.S. App. LEXIS 1466

• Court: Court of Appeals for the Fifth Circuit
• Decided: February 6, 1992
• Docket: 90-4913
• Status: Published

Opinion

W. EUGENE DAVIS, Circuit Judge:

Shell Oil Company appeals the adverse judgment of the Tax Court and its computation of “net income from the property” under Treasury Regulation § 1.613-5(a) for purposes of calculating the net income limitation on the windfall profit tax. More particularly, Shell complains of two of the Tax Court’s conclusions. The Tax Court held first that abandoned geological and geophysical costs may not be treated as overhead and allocated among Shell’s mineral properties. It also held that intangible drilling costs must be included in the allocation base for apportioning overhead among Shell’s oil and gas properties. Shell Oil Co. v. Commissioner, 89 T.C. 371 (1987). We reverse and remand.

I.

Shell Oil Company (Shell) is a fully integrated oil company engaged in many facets of the petroleum business including exploration, production, refining and distribution of crude oil and natural gas. Exploration begins when Shell’s geologists or geophysicists select areas with potential oil and gas reserves. Exploration enters the “probe stage” when Shell decides to investigate these potential reserves further. The exploration department usually starts this investigation by conducting regional geological studies and seismographic testing. The land department then assesses the acreage available for lease and the probable costs of leasing the property. If the exploration, land and production departments agree that a probe warrants further exploration it is termed a “play”. At this stage the exploration department obtains more seismographic data and attempts to map multiple prospects within the play. All departments then pool their information to attempt to calculate the present value of the prospect. The probe and play stages of exploration (and the costs incurred in these processes) are preliminary activities Shell must complete before it acquires any property interests. When Shell’s exploration department concludes from its geological and geophysical research that oil or gas is not present in sufficient quantities to justify further investment, no property interest is acquired in the land on which the surveys were conducted. The costs incurred for probe and play activity on lands in which no property interest is acquired are called abandoned geological and geophysical costs (abandoned G & G). In 1980, Shell abandoned over $65 million in G & G costs, including $28 million incurred before 1980 but abandoned as worthless in 1980.

The above background facts relate primarily to our consideration of the first issue presented in this case — proper treatment of abandoned G & G costs. We will include any additional facts needed to consider the second issue — the proper method of apportioning Shell’s overhead — in our discussion of that issue.

II.

From March 1, 1980, until its repeal effective August 23, 1988, the Crude Oil Windfall Profit Tax Act of 1980, Pub.L. No. 96-223, 94 Stat. 229 (1980), imposed an excise tax on the “taxable windfall profit” from crude oil produced in the United States. Section 4988(b)(1) of the Internal Revenue Code, 26 U.S.C. § 4988(b)(1), limited the taxable windfall profit on any barrel of crude oil to not more than 90% of the net income attributable to that barrel of oil. This net income limitation was to be based on a calculation of net income from the property from which the crude oil was produced. Net income from the property was defined by reference to Code sections and related regulations limiting percentage depletion deductions to 50% of net income from the property. § 613(a) and Treas. Reg. § 1.613-5(a). The rulings and cases interpreting Reg. § 1.613-5(a) for depletion calculation purposes apply to the calculation of net income from the property for windfall profit tax limitation purposes.

In reviewing the Tax Court judgment appealed from, we apply the same standard we use in reviewing judgments rendered by a federal district court. 26 U.S.C. § 7482(a). The Tax Court’s factual determinations must stand unless they are clearly erroneous. We review the Tax Court’s conclusions of law de novo. Dresser Industries, Inc. v. Commissioner, 911 F.2d 1128, 1132 (5th Cir.1990). With this background, we turn to the first issue presented by this appeal.

III.

The first issue concerns how abandoned G & G costs should be accounted for in the computation of net income from the property. The parties agree that this is a purely legal inquiry. Treas.Reg. § 1.613-5(a) governs this calculation which is used to limit the amount of windfall profit tax payable on oil produced from a specific property. The regulation provides in part as follows:

The term “taxable income from the property ...” ... means “gross income from the property” ... 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. [2] These deductible items include operating expenses, certain selling expenses, administrative and financial overhead, depreciation, taxes ..., losses sustained, ... exploration and development expenditures, etc. [3] See paragraph (c) of this section for special rules ... [4] 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. [5] 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.

The first sentence of the regulation provides that “all allowable deductions ... which are attributable to the mining processes ... with respect to which depletion is claimed” may be offset against “gross income from the property”. The central inquiry under this sentence of the regulation is whether abandoned G & G costs are “attributable to mineral processes ... with respect to which depletion is claimed.” The Tax Court held and the Commissioner no longer disputes that the exploration activities which generate abandoned G & G costs are part of the mining process.

The Tax Court agreed with the Commissioner on the meaning of the second phrase “with respect to which depletion is claimed”. The Tax Court focused on the principle that depletion can only be claimed against production on a specific property. It reasoned that abandoned G & G costs may not be attributed to Shell’s producing properties which generate depletion deductions and windfall profit tax liability, because these costs are not incurred to explore a specific property. From this premise, it concluded that abandoned G & G may not be allocated as indirect costs to producing or nonproducing properties. We disagree for two reasons.

First, we do not read the qualifying phrase “with respect to which depletion is claimed” to require that abandoned G & G be incurred on a specific depletable property; rather the full text of sentence [1] requires only that the costs be attributable to the depletable property. See Gen. Couns.Mem. 39099 (Dec. 21, 1983).

Also, Shell’s position that abandoned G & G is in part attributable to producing mineral properties is consistent with the Commissioner’s practice of allowing deductions for other types of expenses unrelated to specific mineral properties. Some of these allowed deductions are much more remote from specific producing properties or even production in general than abandoned G & G. For example, the Commissioner permits Shell to attribute to mineral properties expenses such as health insurance for Shell’s accountants and maintenance costs of Shell’s office buildings which house its executive offices. The costs incurred in preliminary exploration which later prove worthless, benefit producing properties much more directly than these administrative expenses. Exploration is a necessary cost of discovering the fields which may yield producible quantities of oil and gas. We conclude that abandoned G & G costs are an allowable deduction attributable to the mining process with respect to which depletion is claimed and can be allocated as an indirect cost to Shell’s mineral properties. 2

The remaining dispute about abandoned G & G relates to the application of the regulation’s rules governing allocation of costs incurred for more than one purpose and benefiting more than one property. Sentences [4] and [5] of the regulation address these questions. These sentences define how expenses captured by the first sentence, which we have determined include abandoned G & G costs, must be allocated between mining and “other activities” and among the taxpayer’s several properties.

Sentence [4] states that “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”. The purpose of sentence [4] is to allocate joint costs between mineral properties (which generate windfall profit tax) and Shell’s “other activities” (which do not generate windfall profit tax liability). The Commissioner argues that Shell’s preliminary exploration activities which generate G & G costs are an “other activity.” The Commissioner contrasts the phrase “mineral properties” in the regulation’s fourth sentence to “mineral processes” in sentence [1]. He argues that abandoned G & G costs are not incurred on mineral properties as defined and thus fall in the category of “other activities”. “Property” is defined by § 614(a) of the Code to mean “each separate interest owned by the taxpayer in each mineral deposit in each separate tract or parcel of land.” According to the Commissioner, “other activities” includes non-mining activities and mining activities other than those associated with specific producing properties. Rejecting this position, the Tax Court held that “other activities” means non-mining activities.

The Tax Court’s interpretation of “other activities” to include only non-mining activities is correct. Earlier versions of Treas.Reg. § 1.613-5(a) used the phrases “activities in addition to mineral extraction” and “additional activities such as operating refineries and transportation lines” in place of “other activities”. Reg. 77, Art. 221(h) (1931); Reg. 74, Art. 221(i) (1929). We find no indication that the Commissioner intended to change the meaning of this section when he adopted the phrase “other activities” in the later versions of the regulation. Because G & G is part of the mining process, it is not an “other activity”.

We turn next to the parties’ arguments addressed by sentence [5] of the regulation. Shell argues that sentence [5] requires the taxpayer with multiple mineral properties to allocate costs not directly attributable to a specific property (that are captured in the previous sentences of the regulation) among the several properties. 3 The Tax Court disagreed and created a third cost center consisting of abandoned G & G costs. We agree with Shell’s interpretation of sentence [5]. The language of the regulation gives no support to the creation of a third cost center. Sentence [4] of the regulation provides for the allocation of joint overhead costs between only two categories of cost: mineral properties and other activities. Sentence [5] then provides for allocating expenses attributable to multiple mineral properties among the several properties. These sentences of the regulation plainly require the taxpayer to allocate abandoned G & G which is attributable only to mineral properties (and not to other activities) among its several properties.

We conclude, therefore, that abandoned G & G costs are costs “attributable to mining processes” under sentence [1] of Treas.Reg. § 1.613-5(a) and do not constitute an “other activity” under sentence [4]. For purposes of computing net income from the property, sentence [5] requires the taxpayer to treat these costs like other expenses not directly attributable to a specific property interest: they must be apportioned among Shell’s several properties by a proper apportionment formula. We turn next to consider whether the apportionment formula Shell adopted is a proper one.

IV.

The second issue we must decide relates to the propriety of Shell’s formula for apportioning its overhead among its properties as required by sentence [5] of the regulation. A proper formula will assign a reasonable amount of the company’s overhead to each producing property. That figure is needed because each producing property’s share of the overhead will reduce the net income from the property which in turn affects Shell’s windfall profit tax liability on that property.

The parties stipulated to a general apportionment method called the “modified direct expense method.” This formula assigns overhead to each property based on that property’s share of total operating costs. 4 The nub of the dispute is over what costs should be included in total operating costs. The parties have agreed on most of these expenses. They disagree, however, on whether intangible drilling costs should be included. Intangible drilling costs (IDC) are generally the costs incurred in drilling wells. 5

Shell sought to exclude IDC from the allocation base. Shell argues that it incurs relatively little overhead in drilling oil and gas wells because the drilling is done almost exclusively by independent contractors. Consequently, it contends that its allocation method excluding IDC from the allocation base “properly apportions” its indirect costs and therefore meets the standard set by the regulations. The Tax Court found that some overhead is incurred in relation to IDC. It therefore ordered that IDC be included in the allocation base because a base that includes, rather than excludes, IDC results in a “fairer allocation” of indirect expenses.

Sentences [4] and [5] of Treasury Regulation § 1.613-5(a) require only that indirect expenses be “properly apportioned” without specifying any particular apportionment method. They do not specify, as do some other provisions of the Internal Revenue Code and Regulations, that the method selected must be the “best” or “fairest” apportionment method. See for example, § 471(a).

Both Shell and the Commissioner rely on Occidental Petroleum Corp. v. Commissioner, 55 T.C. 115, 124 (1970). In that case the only issue before the tax court was the proper method for allocating certain overhead or indirect expenses among the taxpayer’s various coal mining properties for the purpose of computing the net income limitation for depletion purposes. 6 The taxpayer proposed a method allocating indirect expenses to the properties on the basis of direct expenses incurred in each mine. The Commissioner proposed a method which would allocate indirect costs on the basis of tonnage produced by each mine. In analyzing whether the taxpayer’s method was proper, the Tax Court in Occidental considered whether the taxpayer’s proposed method was “defensible within certain broadly defined cost accounting parameters” as applied to the facts of that case. Id. at 125. In doing so, the court did look at the merits of the Commissioner’s alternative proposal as one measure of the reasonableness of the taxpayer’s method. However, the focus of the inquiry was whether the taxpayer’s proposed method was proper. The approach of the tax court in Occidental is more compatible with the plain requirement of the regulation that a “proper” apportionment be made. Therefore, the tax court should not have asked whether Shell’s apportionment method was “fairer.” It should have asked whether Shell’s apportionment method was “defensible under cost accounting principles.” If so, Shell has “properly apportioned” overhead among its several properties even though Shell’s method may not be the fairest or the most accurate possible method.

We agree with the Tax Court that the question whether a given method of allocation properly apportions indirect expenses for purposes of the net income limi tation is a factual one. Neither the Internal Revenue Code nor the Commissioner’s regulations provide any explicit guidance on how to determine whether a method “properly apportions” costs. The Commissioner notes that the only regulations that refer to proper apportionment are §§ 1.613 — 3(d)(l)(iii) and 1.613-4(d)(4)(iii). Both of these sections indicate that an allocation on the basis of direct costs “may be reasonable in a particular case.” However, these regulations do not mention IDC or answer the question whether IDC is a “direct cost” to be included in the allocation base.

The history of the regulation is also inconclusive. The relevant regulations for more than 30 years contained an illustration of a “fair apportionment” that permitted taxpayers to allocate indirect costs in proportion to direct operating expenses, without reference to IDC. See Treas.Reg. 86, Art. 23(m)-l(h) (1935); Treas.Reg. 94, Art. 23(m)-l(h) (1936); Treas.Reg. 103, § 19.23(m)-l(g) (1940); Treas.Reg. Ill, § 29.23(m)-l(g) (1943); Treas.Reg. 118, § 39.23(m)-l(g) (1953). However, this illustration was deleted from the regulations in 1960 at the same time the regulation was revised to substitute the phrase “fairly apportioned” for “fairly allocated”. See Treas.Reg. § 1.613-4, T.D. 6446, 1960-1 C.B. 208. The wording of the regulation was again revised in 1972, substituting “properly apportioned” for “fairly apportioned”. See T.D. 7170, 1972-1 C.B. 178. Although the Commissioner did not suggest in any of these revisions that substantive changes were intended, and the illustration may still serve as an example of a proper apportionment method in appropriate circumstances, it does not have the force of law that Shell suggests.

Because the regulations do not provide clear guidance to evaluate when an apportionment method is proper, we look, as the Tax Court did in Occidental and below, to general cost accounting principles. We agree with the Tax Court that under these principles, the taxpayer should choose an apportionment method that reflects the purpose to be served by the cost allocation. Specifically, the method should reflect the “beneficial and causal relationship” between the cost objective (in this case, the mineral property) and the indirect costs to be assigned. Shell, 89 T.C. 371, 407 (1987) (the opinion below). According to this general principle, to determine whether Shell’s apportionment method is “proper”, the fact finder must determine whether Shell established that its theory of the relationship between overhead and IDC expenses is reasonable.

The theory behind the “modified direct expense” apportionment method to allocate overhead among Shell’s mineral properties is that the higher the costs incurred on a property, the greater the management and administrative effort required and therefore proportionately more overhead should be allocated to that property. The Commissioner’s apportionment method, including IDC in the allocation base, assumes that this relationship applies equally to direct operating costs and IDC. In 1980, Shell incurred $614 million of IDC and $618 million of direct operating expenses. Therefore, including IDC in the allocation base assumes that approximately one-half of Shell’s overhead is incurred in relation to IDC. Stated differently, the Commissioner’s proposal assumes that Shell’s expenditures on IDC require the same amount of overhead as expenditures on its direct operating expenses.

Shell argues that the Commissioner’s proposal to include IDC in the allocation base grossly distorts the allocation of overhead to each of its mineral properties. It argues that IDC must be excluded from the allocation base because minimal overhead is incurred in relation to the large amount it spends on IDC. According to Shell, this is true because expenditures for drilling wells require less management and administrative effort than its production activities. Shell points out that more than 90% of the drilling work was performed by outside contractors. These contractors incur most of the overhead associated with the process of drilling wells. Shell had only 200 employees engaged in its own drilling operations and supervising contract drillers. In contrast, Shell’s exploration and production departments employed approximately 10,000 employees. In sum, Shell established that although it expends approximately equal dollar amounts on IDC and direct operating expenses, Shell’s expenditures for management and administrative support for drilling wells (which generate IDC) is substantially less than the administrative/management support for the exploration and production activities that generate direct operating costs.

Undoubtedly “some” overhead is incurred in relation to IDC. But this alone does not support rejecting Shell’s method in favor of the Commissioner’s method. Considerable leeway is permitted in the construction of a “proper” apportionment method. Shell has presented a strong case that overhead is incurred in relation to IDC at a much lower rate than it is incurred for direct operating expenses, and therefore that its apportionment method excluding IDC from the allocation base is proper. Shell’s arguments highlight the fact that the analysis of the reasonableness, fairness or propriety of an apportionment method is fact specific and unique to each taxpayer. We therefore conclude that this inquiry is a factual one requiring a remand to the tax court for appropriate findings.

In summary, when evaluating a taxpayer’s apportionment method under Treas.Reg. § 1.613-5(a), the court should ask whether that method “properly apportions” indirect costs. To answer this question, the Tax Court should look at the relationship between the costs to be allocated and the taxpayer’s chosen allocation base and conclude whether the taxpayer’s apportionment method reasonably reflects that relationship. We therefore remand this case to the Tax Court to address this issue following an additional hearing if the Tax Court considers it appropriate.

For the foregoing reasons, we reverse the judgment of the Tax Court as it relates to the treatment of abandoned G & G costs; we vacate the portion of the judgment rejecting Shell’s apportionment method and remand this feature of the case to the Tax Court to determine whether Shell’s method of apportioning overhead among its mineral properties is proper.

REVERSED and REMANDED.

2 . The meanings of the second and third sentences of the regulation are not disputed. The second sentence furnishes a nonexclusive list of deductible items, expressly including “exploration and development" expenditures. Sentence [2] reads, “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.” The fact that exploration costs (which include G & G) are included in sentence [2] as an allowable deduction does not decide the question whether G & G costs incurred on non-acquired land are attributable to mining processes as required by sentence [1].

The third sentence is not applicable to this case. Sentence [3] reads, “See paragraph (c) of this section for special rules relating to discounts and to certain of these deductible items.”

3 . Sentence [5] reads, "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."

4 .

The formula is as follows:

Operating costs of an individual property x Total overhead

Shell’s total operating costs to be allocated

5 . The regulation defines intangible drilling costs as the capital expenditures for “wages, fuel, repairs, hauling, supplies, etc. incident to and necessary for the drilling of wells and the preparation of wells for the production of oil or gas.” Treas.Reg. § 1.612-4(a).

6 . The method of calculating net income from the property to set the net income limitation is the same for depletion and windfall profit tax purposes under regulation § 1.613-5(a).