CCA 200028022: More facts needed on enhanced oil recovery credit costs

Plain-English summary

An oil producer claimed the section 43 credit for costs of generating steam and buying, injecting, and recycling carbon dioxide in enhanced oil recovery projects. Chief Counsel said it lacked enough facts to decide whether those costs qualified. Their treatment could depend on whether they were intangible drilling and development costs, capital costs of tertiary injectants, or ordinary current expenses. Costs deductible under another provision may be excluded from the section 193 category used for the credit. Counsel asked for more detailed facts and suggested a technical advice request if a definitive answer was needed.

Ruling snapshot

• Question: Do steam and carbon dioxide costs qualify for the enhanced oil recovery credit?
• Outcome: Advice given: the available facts did not support a definitive conclusion.
• Key authorities: IRC §§ 43(c)(1), 193, 263(c), 263A, 162.

Full text (IRS public release)

DEPARTMENT OF THE TREASURY
INTERNAL REVENUE SERVICE
WASHINGTON, D.C. 20224
April 11, 2000

Number: 200028022
Release Date: 7/14/2000
Office Symbols: CC:DOM:FS:P&SI
Case Number: TL-N-7490-99
UILC: 43.04-00

MEMORANDUM FOR: Northern California District Counsel CC:W R:NCA:SF attn: Laurel Robinson

FROM: Deborah A. Butler
Assistant Chief Counsel (Field Service)

SUBJECT: Section 43 EOR Credit

Internal Revenue Service National Office Field Service Advice

This Field Service Advice responds to your memorandum dated January 7, 2000. Field Service Advice is not binding on Examination or Appeals and is not a final case determination. This document is not to be cited as precedent.

LEGEND:

X
=
year 1
=
year 2
=
year 3
=

ISSUE(S):

W hether sufficient facts have been provided to our office to determine whether costs associated with preparing and using steam and CO2 as tertiary injectants are deductible under any provision of the Code, other than section 193, for purposes of section 43(c)(1)(C).

CONCLUSION:

That issue, together with the issue of whether any other provision permits the credit, requires further factual refinement before any definitive conclusions can be reached.

FACTS:

• 2 -

X Corporation (hereinafter “X”) claimed tax credits for various costs incurred in connection with enhanced oil recovery (hereinafter “EOR”) projects under Internal Revenue Code (hereinafter “I.R.C.”) § 43 for the taxable years 1 through 3 and for subsequent audit cycles. The credit claimed equaled 15 percent of X’s reported qualified EOR costs. X included tertiary injectant expenses related to EOR projects in computing the credit. These expenses were incurred by X’s conventional steam plants and co-generation plants, in connection with the use of steam-drive and/or cyclic-steam injection in the EOR projects. Other expenses at issue are related to the purchase and injection of CO2 in EOR projects.

X uses both cyclic steam and steam flood methods. Steam is generated in the field by both dedicated steam generation plants and by cogeneration plants. X uses water obtained during oil production (formation water). The steam plants that convert the water to steam burn purchased natural gas. The monthly operating costs of generating the steam, including fuel, labor, plant maintenance, water recycling and utilities, are allocated pro rata to the volume of steam measured in equivalent barrels of water. Steam costs form the basis for X’s reported EOR credit calculations for tax years 1 to 3.

X uses carbon dioxide injection in other fields. X purchases the carbon dioxide from a third party. Purchased carbon dioxide cost, as well as the cost of recycling previously injected CO2 , are allocated pro rata to the quantity of gas injected into each project well during the course of the year. These injected gas costs also form the basis for X’s reported EOR credit. X does not include the costs associated with injecting water into each well after each dioxide injection cycle in the EOR credit computations.

Finally, X uses water flooding in many of its fields. In one field the water flood project involved the completion of over 200 water injection wells through year 3 that, coupled with extensive reservoir fracturing, was expected to increase production. X treats all costs associated with operating the water flooding/injection wells, including separation and recycling of produced water, as currently deductible for tax purposes and partly capital expenditures and partly current expenses for book purposes.

The Service doubts that certain costs relating to the generation of steam, the injection and recycling of CO2, and the injection and recycling of water (including the costs of fuel, labor, plant maintenance, water recycling and utilities) constitute I.R.C. § 193 qualified tertiary injectant expenses. The Service has tentatively concluded that all of these costs are properly deductible under sections of the Code other than I.R.C. § 193 for purposes of section 43(c)(1)(C) and that no other provision of section 43 permits these expenditures to be treated as qualified enhanced recovery costs.

• 3 -

LAW AND ANALYSIS:

Internal Revenue Code section 38(a) allows a business credit against income tax. Sections 38(b) and 43(a) extend the credit to "qualified enhanced oil recovery costs" (hereafter the "EOR credit"). Qualified EOR costs include: (1) amounts paid or incurred for property which is an integral part of a qualified enhanced oil recovery project, and which may be depreciated or amortized; (2) intangible drilling and development costs paid or incurred in connection with a qualified enhanced oil recovery project and for which an election may be made under section 263(c); and (3) qualified tertiary injectant expenses incurred in connection with a qualified enhanced oil recovery project for which a deduction is allowed under section 193. I.R.C. § 43(c)(1).

Revenue Ruling 70-354, 1970-2 C.B. 50, provides that the cost of recoverable gas, utilized for pressure maintenance and in a miscible displacement process, is a capital expenditure. Similarly, Revenue Ruling 73-377, 1973-2 C.B. 84, provides that the cost of the unrecoverable portion of such gas also is capitalizable and recoverable as a depreciable asset. W hether the rationale of these rulings is applicable to self created non-hydrocarbon tertiary injectants would affect the eligibility of such costs for section 43 treatment under section 43(c)(1)(A). This determination has not been definitively made by our office. If it is determined, however, by analogy, that the rulings are applicable to the costs at issue, a determination would be required as to what portion of the injectants are recovered and what portion of the injectants are unrecovered, as well as the respective costs of each portion.

In addition, whether all or part of the expenditures at issue are eligible for section 43 treatment under either the second or third categories listed in the statute similarly is primarily a factual issue. Furthermore, whether the expenditures may be necessary business expenses deductible under section 162 is also a factual question. Resolving these factual issues will require application of the facts to the legal principles that govern. Accordingly, we address the legal predicate for each contending theory so that the underlying facts can establish the appropriate legal theory to be followed.

As stated above, a credit is available for intangible developments costs paid or incurred in connection with a qualified enhanced oil recovery project and for which an election may be made under section 263(c). Although section 263(a)(1) generally requires that costs for permanent improvements or betterments (e.g., development costs) must be capitalized, section 263(c) allows a taxpayer to elect to deduct currently intangible drilling and development costs incurred for oil, gas and geothermic wells.

• 4 -

Treas. Reg. § 1.263(c)-1 incorporates Treas. Reg. 1.612-4(a) for the purposes of this election. Treas. Reg. 1.612-4(a) provides that intangible drilling and development costs incurred by an operator in the development of oil and gas properties, at the option of the operator, may be chargeable to capital or to expense. This option applies to all expenditures made by an operator 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.

Significant questions have arisen in the past as to when development ends. For instance, drilling of injection wells, in some circumstances, has been determined to be a development activity. Page Oil Co. v. Commissioner, 41 BTA 952 (1940)(injection wells IDC), nonacq. on other grounds, 1940-2 C.B.

13. On the other hand, the Tax Court indicated in James A. Lewis
    Engineering v. Commissioner, 39 T.C. 482, 492 (1962), aff’d, 339 F.2d 706 (5 th Cir. 1964), that a water flooding program is “largely a production activity and cannot be capitalized.” This is because ordinary efforts to increase the rate of production of hydrocarbons are treated as normal expenses of the current business cycle, deductible under section 162.

Thus, a preliminary question in this case is whether any portion of the expenditures in issue constitute intangible drilling and development costs that would be subject to the election under section 263(c). This would be the case if the costs do not merely assist in the production of existing recoverable petroleum but, in addition, significantly increase the amount of recoverable reserves. W hether the expenses are subject to the section 263(c) option cannot be determined on the basis of the limited facts provided our office and, thus, factual refinement is required for a definitive resolution of the ultimate issues respecting the appropriateness of the taxpayer’s utilization of the section 43 credit.

In that regard, the following question must be answered: whether such expenses were paid or incurred in connection with “a qualified enhanced oil recovery project.” To qualify as such a project, the project must involve the application (in accordance with sound engineering principles) of one or more tertiary recovery methods (as defined by section 193(b)(3)) which can reasonably be expected to result in more than an insignificant amount of crude oil which will ultimately be recovered. I.R.C. § 43(c)(2)(A). If the tertiary methods at issue here result in significant increases in ultimate recoverable reserves, they would arguably constitute IDC and be eligible for the section 43 credit.

Resolution of these factual questions also determines whether the expenditures may be deducted under section 193. Section 193(a) allows a deduction for qualified tertiary injectant expenses. Treas. Reg. § 1.193-1(a) - 5 -

provides that the deduction is allowed the later of (1) the taxable year the injectant is injected or (2) the taxable year the expenses are paid or incurred.

Section 193(b)(1) defines the term “qualified tertiary injectant expenses” to mean any cost paid or incurred (whether or not chargeable to capital account) for any tertiary injectant (other than a recoverable hydrocarbon) which is used as part of a tertiary recovery method. Additionally, section 193(b)(3)(A) defines the term “tertiary recovery method” to include any method which is described in subparagraphs (1) through (9) of section 212.78(c) of the June 1979 energy regulations (as defined by section 4996(b)(8)(C) as in effect before its repeal). W e note that steam injectants and carbon dioxide injectants are described in subparagraphs (2) and (8) of section 212.78.

Most significantly, section 193(c) provides that no deduction shall be allowed under section 193(a) with respect to any expenditure (1) with respect to which the taxpayer has made an election under section 263(c), or (2) with respect to which a deduction is allowed or allowable under any other provision of Chapter 1 of the Code. Thus, if the expenses in issue are deductible as intangible drilling and development costs under I.R.C. § 263(c), no deduction is allowable under section 193(a). However, the expense may qualify under section 43(c)(1)(B) in this circumstance, even though the expense would fail to qualify for a credit under section 43(c)(1)(C).

Similarly, it must be established whether the cogeneration plant product and the CO2 are held as inventory for the current business cycle, recycled and reused and/or disposed of during the current business cycle. Resolution of those factual questions may allow this office to opine whether the CO2 and cyclic steam are separate assets produced by X whose costs of creation are subject to capitalization. In the event those costs are treated as capital expenditures, they may in turn be treated as section 193 expenses, even though subject to capitalization.

CASE DEVELOPMENT, HAZARDS AND OTHER CONSIDERATIONS:

If the expenses in issue are subject to capitalization under section 263(a) and/or 263A, they might then be deducted under section 193 since that provision allows capitalized expenses to be deducted. This would, at first blush, apparently entitle taxpayer to the section 43 credit for section 193 expenses. However, section 263A may require some of the expenses to be capitalized to inventory. Since some of the costs, arguably, are capitalized to inventory, they would undoubtedly be treated as “cost of goods sold” and reduce gross receipts. Arguably, such costs are in the nature of “deductions” in the ordinary business cycle for purposes of section 193. Expenses which may be deducted in the same taxable year as the injection under a Code provision other than section 193 do not qualify as section 193 expenses - 6 -

subject to the section 43 credit. See I.R.C. §§ 193(c)(2) and 43(c)(1)(C).

Taxpayer’s likely response would be that “cost of goods sold “is not a deduction (within the meaning of section 162(a)) but is an amount subtracted from gross receipts in the determination of the taxpayer’s gross income. Max Sobel W holesale Liquors v. Commisisoner, 69 T.C. 477 (1977), aff’d, 630 F.2d 670 (9 th Cir. 1980); Beatty v. Commissioner, 106 T.C. 268 (1996). See also Treas. Reg. § 1.61-3 which defines income for mining business purposes as total sales less cost of goods sold, including actual inventory costs. Taxpayer may rely on section 193(b)(1) for the proposition which states that an expense is a “qualified tertiary injectant expense” deductible under section 193 “whether or not [any cost is] chargeable to a capital account.” I.R.C. § 193(b)(1). This would tend to support its argument that the phrase “deduction under any other provision” was not intended to refer to reductions for cost of goods sold.

In addition, the legislative history for section 193 supports a broad reading of the statute, explaining that expenditures for tertiary injectants generally are deductible under section 193 in the year to which the tertiary substance is injected into the reservoir. Senate Report 96-394, 98, 1980-3 C.B. 216, states that “[s]uch tertiary injectants generally would include those used in a qualified tertiary enhanced recovery project, as defined under the windfall profit tax, and which the taxpayer establishes are tertiary injectants.” The only limitation appearing in the Senate Report is that tertiary injectants may not include hydrocarbon injectants. The Conference Agreement followed the Senate Amendment and stated this treatment is not elective. H.R. No. 96- 817, 152; 1980-3 C.B. 312. Thus, the legislative history would tend to support treating a capitalized cost as a section 193 expense.

Additionally, if the facts establish that the costs are deductible under section 263(c), the Service may never even be required to reach the capitalization issue. Both section 263(c) and 263A(c)(3) explicitly except IDC from capitalization, and section 43(c)(1)(B), in turn, treats intangible drilling and development costs, incurred in connection with a qualified enhanced oil recovery project, as subject to the section 43 credit. See also Treas. Reg. §§ 1.263A-1(b)(8) and 1.263A-13. Thus,

If a definitive resolution of the issue is required, however, we believe the facts should be thoroughly documented, - 7 -

agreement as to such facts should be obtained from the taxpayer, and a request for Technical Advice from our office should be made. Your office may wish to assist Examination in preparing such Technical Advice request by providing them with a thorough understanding of the factual patterns which would support one or more of the possible legal approaches outlined in this memorandum.

If you have any further questions, please call (202) 622-7830.

By: PATRICK PUTZI
Special Counsel (Natural Resources)
Passthroughs & Special Industries Branch Field Service Division