TAM 201117028: CO2 equipment costs were not deductible under section 193, but retroactive application was limited

Plain-English summary

The IRS considered whether an oil and gas company could deduct the costs of CO2 transportation assets, including pipelines, and CO2 injection and recycling facilities as qualified tertiary injectant expenses under IRC § 193. It concluded that section 193 does not cover tangible equipment costs, so the company could not deduct those costs under that provision. The IRS nevertheless granted relief under section 7805(b), allowing the company to rely on an earlier accounting-method consent for the specified taxable years before revoking that portion of the consent. The relief did not affect the separate permission to deduct CO2 source-well drilling costs under section 616(a), subject to the stated amortization requirement.

Ruling snapshot

• Question: Were CO2 transportation and injection equipment costs deductible under section 193, and if not, should the TAM apply retroactively?
• Outcome: Mixed. The equipment deductions were denied, but section 7805(b) relief was granted.
• Key authorities: IRC §§ 43, 193, 263(c), 291(b), 616(a), 7805(b), and 6110(k)(3); Treas. Reg. §§ 1.193-1, 1.43-4, 601.201, and 601.204; Rev. Proc. 97-27 and Rev. Proc. 2010-2.

Full text (IRS public release)

INTERNAL REVENUE SERVICE
NATIONAL OFFICE TECHNICAL ADVICE MEMORANDUM

December 22, 2010

Third Party Communication: None
Date of Communication: Not Applicable

Number: 201117028
Release Date: 4/29/2011
Index (UIL) No.: 193.00-00, 7805.03-00
CASE-MIS No.: TAM-139013-10

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LB&I-NRC East

Taxpayer's Name: ---------------------------------
Taxpayer's Address: ------------------------------------------------
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Taxpayer's Identification No
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Year(s) Involved: ---------------

LEGEND:

Taxpayer = ---------------------------------
Date 1 = ----------------------
Letter = ----------------------------------------------------
Date 2 = --------------------------
Date 3 = --------------------------
Date 4 = ----------------------

ISSUES:

(1) Are costs paid or incurred for constructed and acquired carbon dioxide (CO2) transportation assets (including pipelines) and CO2 injection field assets (including CO2 injection and recycling facilities) qualified tertiary injectant expenses under § 193 of the Internal Revenue Code (the Code)?

(2) If costs paid or incurred for constructed and acquired CO2 transportation assets (including pipelines) and CO2 injection field assets (including CO2 injection and recycling facilities) are not qualified tertiary injectant expenses under § 193, does the Taxpayer

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qualify for relief under § 7805(b) from retroactive application of this technical advice memorandum (TAM)?

CONCLUSIONS:

(1) Costs paid or incurred for constructed and acquired CO2 transportation assets (including pipelines) and CO2 injection field assets (including CO2 injection and recycling facilities) do not qualify as tertiary injectant expenses under § 193.

(2) Taxpayer’s request for relief under § 7805(b) from retroactive application of this TAM is granted as described below.

FACTS:

Taxpayer is the parent of an affiliated group of domestic corporations engaged in the business of oil and gas exploration, development, and production. Taxpayer owns and operates CO2 and oil production and extraction facilities. Taxpayer purchases and develops mature oil properties with the intention of using tertiary recovery methods to extract additional oil from those properties. Taxpayer uses CO2 injection as its primary tertiary recovery method. Taxpayer owns significant CO2 reserves and also operates CO2 producing wells, production and dehydration facilities, and gathering pipelines, allowing Taxpayer access to the quantities of CO2 necessary for its tertiary oil production program.

Taxpayer extracts CO2 from its reservoirs, gathers the CO2 through its gathering pipelines, processes the CO2 at its production facilities, and transports the CO2 through its pipelines to its oil fields. Taxpayer compresses or pumps the CO2 until it becomes a dense fluid, and Taxpayer then injects the CO2 into an oil reservoir. Depending on the reservoir fluids and conditions such as temperature and pressure, the CO2 will act in either a miscible or immiscible process. The CO2 acts as a type of solvent for the oil, causing it to expand and become mobile, allowing it to move through the reservoir into the well and up to the surface, where Taxpayer recovers the oil along with the CO2.

Construction costs paid or incurred by Taxpayer include the costs of constructing CO2 processing facilities (including dehydration facilities and glycerol/glycol recycling facilities), CO2 pipelines, compression facilities, oil processing facilities, and CO2 recovery and recycling facilities. Acquisition costs include costs to acquire existing CO2 reservoirs, oil and gas reservoirs, existing wells, existing dehydration, purification and recycling facilities, and existing pipelines. Development costs include the costs of preparing reservoir well sites, drilling CO2 reservoir wells, drilling or re-entering CO2 injection and producing wells and installing gathering and distribution lines.

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Taxpayer submitted a Form 3115, Application for Change in Accounting Method, on Date 1, requesting consent to change from its method of capitalizing and depreciating the costs of constructed and acquired CO2 transportation assets (including pipelines) and CO2 injection field assets (including CO2 injection and recycling facilities) to its proposed method of deducting those costs under § 193 beginning with the taxable year ending Date 2. Taxpayer also requested consent to change from its method of capitalizing and depreciating the costs of drilling CO2 source wells to its proposed method of deducting those costs under § 616(a), subject to the 30 percent amortization required under § 291(b) beginning with the taxable year ending Date 2.

The Internal Revenue Service (IRS) national office issued Letter granting Taxpayer consent to change from its method of capitalizing and depreciating the costs of constructed and acquired CO2 transportation assets (including pipelines) and CO2 injection field assets (including CO2 injection and recycling facilities) to its proposed method of deducting those costs under § 193 beginning with the taxable year ending Date 2. Letter also granted permission for Taxpayer to change from its method of capitalizing and depreciating the costs of drilling CO2 source wells to its proposed method of deducting those costs under § 616(a), subject to the 30 percent amortization required under § 291(b) beginning with the taxable year ending Date 2.

The IRS later examined Taxpayer for the taxable year ending Date 2. During its examination of Taxpayer, the IRS Examination Team (Exam) concluded that it would like the IRS national office to reconsider whether § 193 applies to costs of tangible equipment. Specifically, Exam wanted the IRS national office to reconsider whether costs paid or incurred for constructed and acquired CO2 transportation assets (including pipelines) and CO2 injection field assets (including CO2 injection and recycling facilities) are qualified tertiary injectant expenses under § 193. The § 616 costs are not at issue in the TAM.

LAW AND ANALYSIS:

Issue 1:

Are costs paid or incurred for constructed and acquired CO2 transportation assets (including pipelines) and CO2 injection field assets (including CO2 injection and recycling facilities) qualified tertiary injectant expenses under § 193?

Section 193(a) allows as a deduction for the taxable year an amount equal to the qualified tertiary injectant expenses of the taxpayer for tertiary injectants injected during the taxable year.

Section 193(b)(1) defines the term “qualified tertiary injectant expense” as any cost paid or incurred (whether or not chargeable to capital account) for any tertiary injectant (other

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than a hydrocarbon injectant that is recoverable) that is used as a part of a tertiary recovery method.

Section 193(b)(3) defines the term “tertiary recovery method” as any method that is described in subparagraphs (1) through (9) of section 212.78(c) of the June 1979 energy regulations (as defined by § 4996(b)(8)(C) as in effect before its repeal) or any other method to provide tertiary enhanced recovery that is approved by the Secretary for purposes of § 193.

Section1.193-1(d) of the Income Tax Regulations does not allow a deduction under § 193(a) for any expenditure for which the taxpayer has made an election under § 263(c), or for which a deduction is allowed or allowable to the taxpayer under any other provision of chapter 1. Section 1.193-1(a) of the Income Tax Regulations provides, in part, that there shall be allowed as a deduction from gross income an amount equal to the qualified tertiary injectant expenses of the taxpayer. The regulation allows this deduction for the later of (1) the taxable year in which the taxpayer injects the injectant, or (2) the taxable year in which the taxpayer pays or incurs the expenses.

Section 43 generally provides an enhanced oil recovery credit equal to 15 percent of qualified enhanced oil recovery costs paid or incurred by the taxpayer during the taxable year. Section 43(c)(1) provides, in part, that the term qualified enhanced oil recovery costs means any of the following: (A) any amount paid or incurred during the taxable year for tangible property which is an integral part of a qualified enhanced oil recovery project, and with respect to which depreciation (or amortization in lieu of depreciation) is allowable under chapter 1; (B) any intangible drilling and development costs which are paid or incurred in connection with a qualified enhanced oil recovery project, and with respect to which the taxpayer may make an election under § 263(c) for the taxable year; and (C) any qualified tertiary injectant expenses (as defined in § 193(b)) which are paid or incurred in connection with a qualified enhanced oil recovery project and for which a deduction is allowable for the taxable year.

The legislative history underlying § 193 provides insight into the costs that were the intended target of § 193. Section 193 was enacted as part of the Crude Oil Windfall Profit Tax Act of 1980, Pub. L. 96-223, 94 Stat. 229, 1980-3 C.B. 2. The Senate Finance Committee report indicates that one reason Congress enacted § 193 was to clarify the recovery of tertiary injectant expenses. Congress was concerned about the disparate treatment of tertiary injectant expenses depending upon the effect of the injectant on the reservoir. See S. Rep. No 96-394, 96th Cong., 1st Sess. 97 (1979), 1980-3 C.B. 131, 215.

In discussing the tax treatment of tertiary injectant expenses at the time § 193 was enacted, the Senate Finance Committee looked at a number of tertiary injectant expenses and noted the disparate treatment of those costs. For example, generally, taxpayers could currently deduct costs of injectants with a transitory effect on

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production, such as alkaline solutions and CO2. Similarly, taxpayers could currently deduct costs related to injecting a substance with a transitory effect on production. In contrast, generally, taxpayers were required to capitalize and recover through depreciation over the period for which they affected production the expenditures for some injectants which affected production for more than one year. This legislative history indicates that § 193 was not intended to apply to tangible equipment costs.

First, there is no discussion of the treatment of the costs of tangible equipment costs in the Senate Finance Committee report. The Senate report indicates that § 193 was directed toward those costs whose tax treatment could differ depending upon the life of the injectant, that is, the period over which the injected affected production. There would have been no disparate treatment of tangible equipment costs based on the life of the tertiary injectant. Because taxpayers would have used tangible assets to produce, transport, or recycle tertiary injectants for more than one year, these assets would have been capital assets, the costs of which taxpayers always would have recovered through depreciation, without regard to the injectant’s effect on production. Therefore, no uncertainty existed concerning the tax treatment of tangible equipment costs.

Second, prior to the enactment of § 193, the effect of the injectant on the reservoir dictated the tax treatment of tertiary injectant expenses. If the injectant affected production for more than one year, the injectant was a capital asset, the costs of which taxpayers recovered through depreciation. On the other hand, if the injectant had a transitory effect on the reservoir, taxpayers deducted the costs of the injectant currently. Thus, the legislative history underlying § 193 suggests that the language “whether or not chargeable to capital account” contained in § 193(b)(1) refers to the costs that prior to the enactment of § 193 would have been capitalized to, and recovered through depreciation of, the injectant. The equipment, however, is a separate capital asset, the cost of which would have been recovered through depreciation of the equipment.

In addition, the § 43 regulations support the position that tangible equipment costs are not deductible under § 193. When § 43(c)(1)(C) originally was enacted in the Omnibus Budget Reconciliation Act of 1990, Pub. L. 101-508, 104 Stat. 1388, it defined the term “tertiary injectant expenses” to mean any qualified tertiary injectant expenses that are paid or incurred in connection with a qualified enhanced oil recovery project and for which a deduction is allowable under § 193. (Emphasis added.) In December 2000,
§ 317(a)(1)-(2) of the Consolidated Appropriations Act of 2001, Pub. L. 106-554, 114 Stat. 2763, amended § 43(c)(1)(C) to define the term “tertiary injectant expenses” as any qualified tertiary injectant expenses (as defined in § 193(b)) that are paid or incurred in connection with a qualified enhanced oil recovery project and for which a deduction is allowable. (Emphasis added.) Accordingly, for purposes of the amended
§ 43 credit, the tertiary injectant expenses must only be defined in § 193(b) and deductible under any Code provision.

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Section 1.43-4(b) was finalized prior to the amendment of § 43 and thus provides guidance about the costs included in the category of tertiary injectant expenses for which a deduction is allowable under § 193 (emphasis added) as well as guidance about the costs included in the category of tangible property costs. The regulation defines qualified tertiary injectant expenses and tangible property costs separately. Section 1.43-4(b)(3)(i) defines tangible property costs as amounts paid or incurred during a taxable year for tangible property that is an integral part of a qualified enhanced oil recovery project and that is depreciable or amortizable under chapter 1. Section 1.43-4(b)(3)(ii) provides, in part, that tangible property is an integral part of a qualified enhanced oil recovery project if the property is used directly in the project and is essential to the completeness of the project. According to § 1.43-4(b)(3)(ii), generally, property used to acquire or produce the tertiary injectant or property used to transport the tertiary injectant to a project site is property that is an integral part of the project – thus it falls within the category of tangible property. Accordingly, examples of costs for such property as gas processing equipment and pipelines are included in the category of “tangible property costs” and not as tertiary injectant expenses deductible under § 193. Example 1 of § 1.43-4(b) illustrates this in the context of an enhanced oil recovery project that uses steam. The example concludes that the cost of water to produce steam is a tertiary injectant expense, but property such as the equipment to remove the gas and water from the oil after it is produced and the water storage tanks are tangible property.

Although guidance issued by the IRS subsequent to the amendment of § 43(c)(1)(C) indicates that the definition of the term “qualified tertiary injectant expenses” is broader than the costs deductible under § 193, the guidance does not indicate that tangible equipment costs are tertiary injectant expenses. Rev. Rul. 2003-82, 2003-2 C.B. 125 1 holds that the term “tertiary injectant expenses” includes both the cost of acquisition (whether produced or acquired by purchase) of the tertiary injectant and also certain operating expenses related to the use of the tertiary injectant. Under the facts of Rev. Rul. 2003-82, the costs at issue included costs to inject, recover, and reinject the purchased and produced tertiary injectants. Thus, the revenue ruling applies only to operating expenses, that is, the costs of using the injectant. Rev. Rul. 2003-82 does not state or suggest that tangible equipment costs are considered qualified tertiary injectant expenses under § 193.

Therefore, qualified tertiary injectant expenses under § 193 do not include tangible equipment costs. Accordingly, Taxpayer may not deduct as qualified tertiary injectant expenses under § 193 costs paid or incurred for constructed and acquired CO2 transportation assets (including pipelines) and CO2 injection field assets (including CO2 injection and recycling facilities).

1
This document was written for purposes of § 43(c)(1)(C), but Rev. Rul. 2003-82 held that the term “qualified tertiary injectant expenses” for purposes of § 43(c)(1)(C), as amended, has the same meaning as for purposes of § 193.

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Issue 2:

If costs paid or incurred for constructed and acquired CO2 transportation assets (including pipelines) and CO2 injection field assets (including CO2 injection and recycling facilities) are not qualified tertiary injectant expenses under § 193, is Taxpayer entitled to relief under § 7805(b) from retroactive application of this TAM?

Section 7805(b)(8) provides that the Secretary may prescribe the extent, if any, to which any ruling (including any judicial decision or any administrative determination other than by regulation) relating to the internal revenue laws shall be applied without retroactive effect.

Under section 10.01 of Rev. Proc. 97-27, 1997-1 C.B. 680, 690, a taxpayer that changes to a method of accounting pursuant to this revenue procedure may be required to change or modify that method of accounting for the following reasons: (1) the enactment of legislation; (2) a decision of the United States Supreme Court; (3) the issuance of temporary or final regulations; (4) the issuance of a revenue ruling, revenue procedure, notice, or other statement published in the Internal Revenue Bulletin; (5) the issuance of written notice to the taxpayer that the change in method of accounting was granted in error or is not in accord with the current views of the Service; or (6) a change in the material facts on which the consent was based.

Under section 10.02 of Rev. Proc. 97-27, except in rare or unusual circumstances, if a taxpayer changes its method of accounting under Rev. Proc. 97-27 and is subsequently required under section 10 of Rev. Proc. 97-27 to change or modify that method of accounting, the required change or modification will not be applied retroactively provided that: (1) the taxpayer complied with all the applicable provisions of the Consent Agreement and this revenue procedure; (2) there has been no misstatement or omission of material facts; (3) there has been no change in the material facts on which the consent was based; (4) there has been no change in the applicable law; and (5) the taxpayer to whom consent was granted acted in good faith in relying on the consent, and applying the change or modification retroactively would be to the taxpayer’s detriment.

Under section 11.01 of Rev. Proc. 97-27, as modified by Rev. Proc. 2009-39, 2009-38 I.R.B. 371, the director must apply a ruling obtained under this revenue procedure in determining the taxpayer’s liability unless the director recommends that the ruling should be modified or revoked. The director will ascertain if: (1) the representations on which the ruling was based reflect an accurate statement of the material facts; (2) the amount of the § 481(a) adjustment was properly determined; (3) the change in method of accounting was implemented as proposed in accordance with the terms and conditions of the Consent Agreement and this revenue procedure; (4) there has been any change in the material facts on which the ruling was based during the period the

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method of accounting was used; and (5) there has been any change in the applicable law during the period the method of accounting was used.

Under section 11.02 of Rev. Proc. 97-27, if the director recommends that the ruling (other than the amount of the § 481(a) adjustment) should be modified or revoked, the director will forward the matter to the national office for consideration before any further action is taken. Such a referral to the national office will be treated as a request for technical advice, and the provisions of Rev. Proc. 97-27 (or any successor) will be followed.

Under section 13.01 of Rev. Proc. 2010-2, the holdings in a TAM are applied retroactively, whether they are initial holdings or they are later holdings that modify or revoke holdings in a prior TAM. The Associate Chief Counsel with jurisdiction over the TAM, however, may exercise the discretionary authority under § 7805(b) to limit the retroactive effect of any holding. The Associate Chief Counsels exercise this authority in rare and unusual circumstances.

Under section 13.02 of Rev. Proc. 2010-2, a TAM may be used to seek revocation or modification of an earlier TAM or revocation or modification of a private letter ruling. Generally, a TAM that revokes or modifies a letter ruling or an earlier TAM will not be applied retroactively if: (1) the applicable law has not changed; (2) the taxpayer directly involved in the letter ruling or earlier TAM relied in good faith on it; and (3) revocation or modification would be detrimental to the taxpayer. The new TAM will be applied retroactively to the taxpayer whose tax liability was directly involved in the letter ruling or TAM if: (1) controlling facts have been misstated or omitted; or (2) the facts at the time of the transaction are materially different from the controlling facts on which the letter ruling or earlier TAM was based. If a letter ruling or a TAM is modified or revoked with retroactive effect, the notice to the taxpayer, except in fraud cases, should set forth the grounds on which the modification or revocation is being made and the reason why the modification or revocation is being applied retroactively.

Section 13.04 of Rev. Proc. 2010-2 provides that under § 6110(k)(3), a taxpayer may not rely on a TAM issued by the Service for another taxpayer. In addition, retroactive or non-retroactive treatment to one member of an industry directly involved in a letter ruling or TAM does not extend to another member of that same industry, and retroactive or non-retroactive treatment to one client of a tax practitioner does not extend to another client of that same practitioner.

Under section 14.01 of Rev. Proc. 2010-2, a taxpayer to whom a TAM is issued or for whom a TAM request is pending may request that the appropriate Associate Chief Counsel limit the retroactive effect of any holding in the TAM or of any subsequent modification or revocation of the TAM. For a pending request for technical advice, the taxpayer should make the request for relief under § 7805(b) as part of the initial request

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for advice. The Associate office will consider a request for relief under § 7805(b) made at a later time if there is justification for having delayed the request.

Under section 14.05 of Rev. Proc. 2010-2, when a TAM grants a taxpayer relief under
§ 7805(b), the director may not request reconsideration of the § 7805(b) issue unless the director determines there has been a misstatement or omission of controlling facts by the taxpayer in its request for § 7805(b) relief.

Section 601.201(l)(1) of the procedural regulations provides, in part, that a ruling, except to the extent incorporated in a closing agreement, may be revoked or modified at any time in the wise administration of the taxing statutes. If a ruling is revoked or modified, the revocation or modification applies to all open years under the statutes, unless the Commissioner or his delegate exercises the discretionary authority under § 7805(b) of the Code to limit the retroactive effect of the revocation or modification.

Under § 601.201(l)(4) of the procedural regulations, a ruling found to be in error or not in accord with the current views of the IRS may be modified or revoked. Modification or revocation may be effected by a notice to the taxpayer to whom the ruling originally was issued, or by a revenue ruling or other statement published in the Internal Revenue Bulletin.

Under § 601.201(l)(5) of the procedural regulations, except in rare or unusual circumstances, the revocation or modification of a ruling will not be applied retroactively with respect to the taxpayer to whom the ruling was originally issued or to a taxpayer whose tax liability was directly involved in such ruling if (i) there has been no misstatement or omission of material facts, (ii) the facts subsequently developed are not materially different from the facts on which the ruling was based, (iii) there has been no change in the applicable law, (iv) the ruling was originally issued with respect to a prospective or proposed transaction, and (v) the taxpayer directly involved in the ruling acted in good faith in reliance upon the ruling and the retroactive revocation would be to his detriment.

A letter granting consent to a change in accounting method is a letter ruling. A letter ruling found to be in error or not in accord with the current views of the IRS may be revoked or modified. See § 601.204(c) of the procedural regulations. See also § 11.04 of Rev. Proc. 2010-1, 2010-1 I.R.B. 1. When a letter ruling is revoked, the revocation applies to all years open under the statute of limitations unless the IRS exercises its discretionary authority under § 7805(b) to limit the retroactive effect of the revocation. See id.

Based on the circumstances in this case, we conclude that the criteria for § 7805(b) relief have been satisfied and Taxpayer is entitled to relief. Therefore, this TAM will be applied without retroactive effect. Taxpayer may continue to rely on the Letter from the taxable year ending Date 2 through the taxable year ending Date 3. Commencing with

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the taxable year beginning Date 4, that portion of the Letter granting Taxpayer consent to change from capitalizing and depreciating the costs of constructed and acquired CO2 transportation assets (including pipelines) and CO2 injection field assets (including CO2 injection and recycling facilities) to deducting those costs under § 193 is revoked. Accordingly, commencing with the taxable year beginning Date 4, Taxpayer may rely only on that portion of the Letter granting consent for Taxpayer to change from capitalizing and depreciating the costs of drilling CO2 source wells to deducting those costs under § 616(a), subject to the 30 percent amortization required under § 291(b) beginning with the taxable year ending Date 2.

CAVEAT(S):

A copy of this technical advice memorandum is to be given to the taxpayer(s). Section 6110(k)(3) of the Code provides that it may not be used or cited as precedent.