Petroleum Industry Overview Series - Significant Law and Important Issues

Issue was decoordinated on May 5, 2008. See memo below:

May 5, 2008

FROM:  Frank Y. Ng   /s/ Frank Y. Ng
              Commissioner, Large and Mid-Size Business Division

SUBJECT:  Decoordination of Issue for Petroleum Industry:  Estimated Dismantling and Removal Cost

The decoordination of the issue of Estimated Dismantling and Removal Cost has been approved effective the date of this memorandum.   

In 1984, Congress enacted IRC Section 461(h) which added the economic performance test to the all events test of section 461.  This change effectively eliminated this issue in regards to liabilities arising after July 18, 1984.  For pre-461(h) examination years, the Appeals Settlement Guidelines allowed taxpayers to amortize over 25-years the estimated dismantling and removal costs relating to jacket-type platforms located in the Gulf of Mexico or along the coast of California in less than 500 feet of water.  The Coordinated Issue Paper (CIP) was kept primarily to track this settlement on affected taxpayers’ subsequent years.   

On August 31, 2007, Appeals decoordinated this issue due to no activity.  There has been no examination activity on this issue in recent history.  While a potential issue might exist when a taxpayer disposes of pre-461(h) assets, the current CIP has no effect on the correct resolution of the issue.  Accordingly, this issue is being decoordinated.  However, it should be noted that the decoordination of this issue does not result in a change in the Service’s position, but merely removes it from the formal coordination process. 

If you have any questions, please contact me, or a member of your staff may contact Terry Loendorf, Petroleum Industry Technical Advisor, at 972-308-1578

Issue # 1:  Whether a taxpayer is required to include in the original reserve estimate proved undeveloped and probable reserve categories in the total number of recoverable units for the purpose of computing cost depletion under IRC § 611(a).

IRS Position:  Proved developed, proved undeveloped, and “probable and prospective” reserves are regularly estimated using methods current in the industry.  For purposes of computing cost depletion, the taxpayer is required to include all recoverable units of minerals in the total number of recoverable units at the end of the year.  Recoverable units include both proven reserves (developed and undeveloped) and, under appropriate circumstances, additional reserves.

Issue # 2:  Whether a taxpayer is permitted to revise the original reserve estimate based solely on changes in economic factors.

IRS Position: For purposes of cost depletion, the taxpayer is not permitted to revise its reserve estimate based solely on changes in economic factors, without operations or development work indicating the physical existence of a materially different quantity of reserves than originally estimated to purchase the property or develop the property.

Recent Litigation:  Martin Marietta Corp. v. United States,  7 Cl. Ct. 586, 85-1 USTC 9284 (Cl. Ct. 1985)

Status:  Appeals settlement guidelines approved February 27, 2008.

On March 8, 2004, Revenue Procedure 2004-19 was issued.  The revenue procedure provides an elective safe harbor that the owner of domestic oil and/or gas properties may use in determining the property’s recoverable reserves for purposes of computing cost depletion under § 611 of the Internal Revenue Code.  The safe harbor allows taxpayers and the Service to avoid complex factual arguments over what constitutes the appropriate quantity of probable or prospective reserves for purposes of computing cost depletion.  Under the safe harbor, the Internal Revenue Service will not disturb a taxpayer’s estimate of an oil and/or gas property’s total recoverable units where that estimate is equal to 105 percent of the property’s proved reserves as defined in the Security and Exchange Commission Regulations (17 C.F.R. section 210.4-10(a) of Regulation S-X) remaining as of the taxable year. 

When a taxpayer does not elect to use the safe harbor provided in Rev. Proc. 2004-19 for all of its domestic oil and gas properties, examiners should follow the Petroleum Industry Coordinated Issue Paper on Cost Depletion - Recoverable Reserves dated January 13, 1997.

For taxable years ending prior to March 8, 2004, examiners should request assistance of the Petroleum Industry Technical Advisors in resolving the issue.  See NRC Field Directive on Cost Depletion - Determination of Recoverable Reserves.

Issue # 1: What is the meaning of “minority interest” as used in the North Sea IDC transition rule?

IRS Position:  Although the transition rule does not define “minority,” income tax regulations promulgated for other purposes have defined that term to mean an interest of less than 50%. See section 1.332-5 of the Income Tax Regulations (“Distributions in liquidation as affecting minority interests”) and section 1.337-5 of the regulations (“Special rules for certain minority shareholders’).  There is no suggestion that Congress intended to have a different meaning than this usual one.

Issue # 2:  When is a minority interest for development acquired for purposes of the North Sea IDC transition rule?

IRS Position:  The transition rule requires that a United States company acquire a minority interest in a  North Sea development license on or before December 31, 1985.  A minority interest in a North Sea development “license” is established when specific authority to develop the offshore production license is obtained from the appropriate governmental agency.

Issue # 3: Does the transition rule override the amendments to IRC § 291(b) made by the TRA, so that the change from mandatory capitalization of 20 % of intangible drilling costs (“IDC”) over 36 months to capitalization of 30% of IDC over 60 months would not apply to foreign IDC described in the transition rule?

IRS Position:  The transition rule overrides the amendments to I.R.C. 291(b) made by the TRA.  A company meeting the transition rule may continue to capitalize 20% of its foreign IDC over 36 months.

Status: Appeals settlement guidelines approved April 2, 2002.

Issue:  Whether delay rentals paid or incurred under an oil and gas lease are subject to capitalization under IRC § 263A as costs of producing property?

IRS Position: For tax years beginning after December 31, 1993, delay rentals incurred under an oil and gas lease are required to be capitalized to the depletable basis of the property to which they relate pursuant to IRC § 263A if the lease is held for development or if development of the lease is reasonably likely at some future date.  A taxpayer that performs geological and geophysical surveys (G&G) on acquired leaseholds or files a plan of development with an appropriate governmental agency has demonstrated an unequivocal intention to develop the leasehold in the future. Even in the absence of such unequivocal steps, it can be presumed that taxpayers in the business of producing oil and gas acquire leasehold interests with the intent to develop them.  Therefore, unless the taxpayer can establish by credible evidence that the leasehold was acquired for some reason other than development, the taxpayer must capitalize the delay rentals incurred with respect to that leasehold.

IRC § 263A, its legislative history and the temporary regulations all indicate that carrying charges, such as delay rentals, are subject to capitalization under IRC § 263A. Accordingly, it is not reasonable for taxpayers/lessees to rely on Treas. Reg. § 1.612-3. See Proposed Regulation (REG-103882-99) that would conform the regulations on delay rental to the requirements of IRC § 263A.

For tax years beginning before January 1, 1994, a taxpayer must take a “reasonable position” on its federal income tax return when applying IRC § 263A to delay rentals. Some examples of reasonable positions include (1) capitalizing delay rentals on leaseholds that the taxpayer (i) had a plan to produce, (i.e., to develop) or (ii) acquired and thereafter gathered G&G data and (2) capitalizing delay rentals on leaseholds in amounts equal to the taxpayer’s historical percentage of actual leasehold development.  In any event, capitalization of zero delay rentals is not a reasonable position. See TAM 9602002, which holds that deducting delay rentals is not a reasonable position under the temporary regulations.

Recent Litigation: John J. Reichel v. Commissioner, 112 T.C. No. 2, No. 23143-97 (January 7, 1999) and Von-Lusk v. Commissioner, 104 T.C. 207 (1995)

Status: Appeals settlement guidelines were approved April 2, 2003. Successful settlements have been reached at the examination level with little examination time expended by using Delegation Order 4-25 procedures.  It is recommended you contact Terry Loendorf, Petroleum Industry Technical Advisor, at 972-308-1578,  to request implementation of this delegation order.

Issue: Whether the costs incurred to (i) remove and replace underground storage tanks, (ii) clean-up soil contaminated by releases from the tanks, and (iii) install monitoring systems, wells, or other equipment associated with groundwater clean-up are capital expenditures under IRC §§ 263(a) and 263A or currently deductible under IRC § 162?

IRS Position: Costs incurred to remove and replace underground storage tanks are capital expenditures under IRC §§ 263(a) and 263A.  These costs must be capitalized to the basis of the new tank. Costs incurred to remove underground storage tanks and remediate the soil, in cases where the tanks will not be replaced, are deductible under IRC § 162, where the costs are incurred by the same taxpayer that contaminated the property. This does not apply in cases where the costs are incurred to adapt the property to a new or different use.

Costs incurred to clean-up the soil are deductible as business expenses under IRC § 162, where such costs are incurred by the taxpayer who contaminated the property.

Costs of installing monitoring systems, wells, or other equipment associated with the remediation and clean-up of the contaminated area, including direct and allocable indirect costs under IRC § 263A, must be capitalized to the basis of the equipment. These costs may be recovered over the appropriate period determined under IRC § 168.

See Revenue Ruling 2000-7, 2000-9 IRB 1 (February 8, 2000) The Service ruled that the costs of removing an asset to replace it does not have to be capitalized under IRC § 263(a) or 263A as part of the cost of the replacement asset.  The Service cautioned, however, that its analysis did not apply to the removal of a component of a depreciable asset, the costs of which are either deductible or capitalized based on whether replacement of the component is a repair or improvement.

Status:  The coordinated issue paper was revised to conclude that the underground storage tank is a part of the fuel distribution system and not a separate asset for depreciation purposes.  As a component of the fuel distribution system, the removal costs of the underground storage tanks are not within the scope of Rev. Rul. 2000-7 and are capital improvements.

Appeals settlement guidelines are pending.

Issue: Should above ground storage tanks (ASTs), used for marketing petroleum products and placed in service after 1986, be depreciated over 15 years under MACRS asset class 57.1 (inherently permanent property), or should they be depreciated over 5 years under MACRS asset class 57.0 (tangible personal property)?

Many petroleum company taxpayers have petroleum product storage tanks located at bulk plant terminal facilities and other locations. Petroleum products are held in those tanks for distribution to the taxpayer’s customers or to the taxpayer’s retail outlets. Petroleum products must be stored during the distribution process, and steel above ground storage tanks play a major role in such storage.  Field-erected tanks are generally large in size and built to remain in one location. Shop-built tanks are shipped to the site for installation. Taxpayers claim above ground storage tanks should be depreciated over 5 years under MACRS asset class 57.0.

Three asset classes of Rev. Proc. 87‑56 are pertinent in classifying a taxpayer's storage tanks. The asset classes include the business activities set out in (i) asset class 57.0, "Distributive Trades and Services,” ( ii ) asset class 57.1, "Distributive Trades and Services . . . Petroleum Land Improvements,” and, (iii) asset class 00.3, ”Land Improvements," a specific asset class.

Asset class 57.0 includes assets used in wholesale and retail trade, and personal and professional services. It also includes IRC § 1245 assets used in marketing petroleum and petroleum products. In pertinent part, asset class 57.1 includes depreciable land improvements, whether IRC § 1245 property or IRC § 1250 property, used in the marketing of petroleum and petroleum products. It excludes all other land improvements.

Asset class 00.3 includes improvements directly to or added to land, whether such improvements are IRC § 1245 property or IRC § 1250 property, provided such improvements are depreciable. However, that asset class does not include land improvements that are explicitly included in any other class. Because assets used in the marketing of petroleum or petroleum products are included within assets classes 57.0 or 57.1, they cannot be included within asset class 00.3.

Status:  In a recent decision (PDV America Inc., et al. v. Commissioner, T.C. Memo. 2004-118) (United States Tax Court), Tax Court Judge L. Paige Marvel held that the above ground storage tanks of CITGO Petroleum Corp. were not permanent structures, according to the six-factor test of Whiteco Indus. v. Commissioner, 65 T.C. 664 (1975), and are in MACRS asset class 57.0 and treated as five-year property under section 168 (e) (1).  It is recommended that you contact the Petroleum Technical Advisors prior to working this issue.

An oil refinery converts crude oil into products, which it then distributes and markets.

Taxpayers assert that certain refinery plant assets should not be classified as MACRS Guideline Class 13.3 relating to refining for depreciation purposes. Taxpayer argues that the assets at issue are not used in “refining crude petroleum into gasoline or the components of crude petroleum.” They claim these assets fall under MACRS Guideline Class 28.0 relating to the manufacture of chemical products.

Assets used in the following processes are those claimed to be chemical assets:

• Sulfur recovery and production
• Hydrogen production
• Isomerization
• Ether Production (MBTE and TAME)
• Olefin Splitter
• Catalytic reformation including naphtha hydrotreaters
• Aklylation

On April 8, 2002, a LMSB Field Directive on MACRSs Asset Categories for Refining Assets was issued.  It is recommended that examiners take the following positions:

• All processing assets involved in the activity of petroleum refining are to be included in MACRS Asset Class 13.3.  This would include any incidental manufacturing or waste removal processes, which are integral parts of petroleum refining.
• In cases where a taxpayer is engaged in more than one industrial activity, the activity in which the asset is primarily used controls the asset's classification.  For example, in addition to using MTBE produced primarily from intermediate refinery process streams as an additive in their own gasoline blending process, a taxpayer may sell the MTBE produced to third parties as a finished chemical.  Primary use of the MTBE asset in either the refining activity or the chemical manufacturing activity will be determinative as to which Asset Class (13.3 or 28.0) is used.

The Directive was exemplified in Technical Advice Memorandum (TAM) 200629031 issued on March 10, 2006.  The Service ruled in the TAM that process units used to produce gasoline and other products of crude petroleum were properly included in the asset class 13.3 petroleum refining because all the units were integral parts of a highly integrated refinery.  The TAM stated in part:

In terms of the functional use of any one of the Units, the product(s) of the Unit and the use of the product(s) determine whether the asset is used in Petroleum Refining activity or Manufacture of Chemical activity. Applying this use-driven functional standard, the Units were dedicated to producing gasoline and other petroleum products and were an integral part of this function. At Facility, Taxpayer was engaged in only this industrial activity; thus, its primary and only use was the production of gasoline and other petroleum products.

This is the primary LIFO inventory issue being pursued by examiners of petroleum companies. Substantially all petroleum companies account for crude oil as one item. They also account for each grade of gasoline as one item.

The National Office has issued ruling letters relating to item definition of gasoline requiring the taxpayers to account for each grade and major type of gasoline they manufacture as a separate item. In some cases, a taxpayer many have as many as 25 different grade types.

While there has been acceptance of the definitions for gasoline, taxpayers raised a number of concerns regarding defining separate crude oil items. For instance, by virtue of the fact that crude oil is a naturally occurring substance composed of a variety of hydrocarbon molecules rather than a substance which is man-made and produced according to a precise formula, the API gravity and sulfur content of crude oil even within the same field of origin are not necessarily uniform throughout the field.  Also, in addition to the variations in the physical characteristics of crude oil occurring within one field, crude oil sold under a particular commercial name is often itself a mixture of crude oils from two or more separate fields. A Crude Oil Study prepared by the Petroleum Industry Program provided a classification system that allowed for the grouping of like-kind crude oils of similar API and sulfur content. The National Office has issued ruling letters allowing taxpayers to “group” grades of crude oil into categories by API and sulfur content. The groupings are separated into 10 API categories and 5 sulfur content categories.  Although there are 50 potential item categories, taxpayers generally have well under 50 that actually apply.

Section 43 of the Internal Revenue Code provides an enhanced oil recovery (EOR) credit equal to 15 percent of the qualified costs paid or incurred by the taxpayer in regards to qualified EOR projects.  Qualified projects must employ certain types of tertiary recovery methods and be reasonably expected to result in an increased recovery of crude oil.  The projects must be located in the United States and have commenced after December 31, 1990.  The types of costs which will qualify for the EOR tax credit generally consist of:

• Tertiary injectant expenses
• Tangible property costs.
• Intangible drilling and development costs.

Two major issues have arisen to date – the “significant expansion issue” and the “tertiary injectant costs issue”.

A significant expansion is meant to relate to a reservoir volume that was not being affected by the EOR project already in existence at the beginning of 1991.  The EOR credit is meant to apply to projects that were “new” as of 1991 or for the ‘significant expansion” of EOR projects that were already in existence at that time.  Issues are being raised when it appears that the qualified costs are applicable to projects in existence at December 31, 1990 that did not result in a significant expansion to the reservoir volume.  TAM 103300-05 (issued as PLR 200535028 on May 5, 2005) addressed this issue.

Tertiary injectant expenses include costs related to the use of a tertiary injectant, as well as expenditures related to the acquisition of the injectant.  However, qualified tertiary injectant expenses do not include costs that a taxpayer paid or incurred in the development or operation of mineral property if an enhanced oil recovery project had not been implemented with respect to the property.  Nor does it include costs related to the use of a tertiary injectant that are also related to other activities, such as primary and secondary recovery.  These related costs must be reasonably allocated among the tertiary   injectant and other activities to determine the amount of tertiary injectant expenses paid or incurred by the taxpayer on the qualified project.  See Revenue Ruling 2003-82.  Issues are being raised when it appears taxpayers are not making this reasonable allocation to primary and secondary recovery activities.

Additional guidance on the EOR credit is available in section 4.41.1.3.4 of the IRM Oil and Gas Handbook. 

The EOR tax credit was designated as a Tier II issue, and the Industry Director for Natural Resources and Construction issued a directive on May 7, 2007 for examiners to follow.

Most major oil companies have image upgrade programs which reimburse independently owned gasoline stations for certain approved expenditures. In most cases, these expenditures are for upgrading the independents' facilities so that they meet the majors' image and appearance standards. The majors commonly reimburse the independents for costs incurred in purchasing equipment, making building improvements, and purchasing advertising, uniforms, and signs.

Under most image upgrade programs, an independent operator enters into a marketing contract for 3 to 8 years or agrees to buy a certain quantity of gasoline. The largest reimbursements generally go to those independents which purchase the largest volumes of gasoline.

There are two issues regarding image upgrade payments: (1) whether the payers should capitalize and amortize the payments; and (2) whether the recipients should include the payments in income. The argument for capitalization by payers is straightforward. The payers make the payments to the independent retailers in order to increase revenue by upgrading the retail facilities. This upgrading has the effect of stimulating sales by encouraging old customers to continue to patronize a major's brand and attracting new customers. The enhanced marketability represents an intangible asset which can reasonably be expected to have value extending beyond the taxable year. Furthermore, there is usually a direct connection between the obligation to make image upgrade payments and the signing of a long-term marketing contract.

On the second issue, I.R.C § 61 defines gross income as all income from whatever source derived, unless excluded by law. Many recipients take the position that the image upgrade reimbursements are excludible from income because they are loans. This is premised on the fact that many of the image upgrade agreements call for repayment of the reimbursements if a recipient fails to buy a certain quantity of gasoline. The Tax Court rejected this theory in Colombo v. Commissioner, T.C. Memo. 1975-162. The Service also concluded in TAM 9308001 (Nov. 9, 1992) that the reimbursements constitute taxable income.

In the recently tried Erickson Post Acquisition, Inc. v. Commissioner, T.C. Memo. 2003-218 (July 22, 2003), the Tax Court held that a gas station corporation received a loan and not deferred compensation, and that the loan wasn't includable in the corporation's income. 

The Service thinks that the Tax Court erred in finding that the $ 175,000 payment to petitioner was a loan. In form, the parties did cast the transaction as a loan.: Amoco and the petitioner executed a note secured by a duly recorded mortgage. However, the evidence strongly suggests that the payment was not really a loan in substance. To constitute a loan, at the time an amount is transferred, the recipient must intend to repay the amount and the transferor must intend to enforce repayment. Beaver v. Commissioner, 55 T.C. 85, 91 (1970). The record establishes that neither the petitioner nor Amoco expected that the money would be repaid. Petitioner treated the advance as deferred income, not a loan, for both book and tax purposes. Petitioner characterized the advance as a loan only after the Service challenged deferral. If the advance had been a true loan, petitioner would have deducted interest and reported forgiveness of debt income once a year on its book and returns.

The Service considers the opinion in Karns Prime & Fancy Foods, Ltd. vs. Commissioner, T.C. Memo. 2005-233, the better analysis. On facts very similar to this case, the court focused on the substance of the transaction and found it an advance payment of income. Karns is consistent with the analysis in other cases addressing the loan versus advance payment issue. See Westpac Pacific Foods v. Commissioner, T.C. Memo. 2001-175, and Columbo v. Commissioner, T.C. Memo. 1975-162. (The Westpac decision was reversed by the 9^th Circuit Court of Appeals.  Counsel is currently reviewing the decision.)

Status Update:  In an action on decision, the IRS recommended a Non-acquiescence, No Appeal.  The Service disagreed with the holding in Erickson Post but did not appeal because it was essentially a factual determination. However, the Service will continue to litigate this issue in cases where taxpayers attempt to avoid tax by characterizing payments or business services as nontaxable loans.

Issue: Whether gas gathering pipeline system assets should be classified, for depreciation purposes, under MACRS class life 46.0, Pipeline Transportation, or MACRS asset class life 13.2, Exploration for and Production of Petroleum and Natural Gas Deposits?

Asset Class 13.2, Exploration & Production of Petroleum and Natural Gas (7- year life), includes gathering pipelines and related storage facilities used by petroleum and natural gas producers to drill wells or produce gas.    

Asset Class 46.0, Pipeline Transportation(15-year life) includes assets used in the private, commercial, and contract carrying of petroleum, gas, and other products by means of pipes and conveyors.   

In Duke Energy Natural Gas v. Commissioner, 172 F.3d 1255 (10^th Cir. 1999), rev’g 109 T.C. 416 (1997), the Tenth Circuit held that natural gas “gathering systems” are property includible in asset class 13.2 and must be depreciated over a 7-year period.  

In Saginaw Bay Pipeline Company, 338 F.3d 600 (6^th Cir. 2003), rev’g and rem’g 124 F. Supp. 2d 465 (E.D. Mich. 2001) the 6^th Circuit Court of Appeals ruled that a company's underground natural gas pipelines should be depreciated over a seven-year period as a gathering pipeline, even though the pipeline owners aren't producers of natural gas.

This was followed by the 8^th Circuit Court of Appeals decision in Clajon Gas Company LP.,   v. Commissioner, 354 F.3d 786 (8^th Cir. 2004), rev’g 119 T.C. 197 (2002) that Clajon primarily used the gathering system in a manner that falls within the description of asset class 13.2.  The court stated Clajon’s use was primarily for gathering pipelines and that asset class 13.2 provision's language did not require that the producer be the owner of the gathering system assets.

The uncertainty regarding the appropriate recovery period of natural gas gathering lines resulting from the above litigation was settled by the enactment of the Energy Policy Act of 2005, House Bill Section 1326 – Natural gas gathering lines treated as 7-year property.  (Primary Code Section 168(e)(3)(C)(iv). 

The new legislation established a statutory seven-year recovery period and a class life of 14 years for natural gas gathering lines the original use of which commenced with the taxpayer and placed in service after April 11, 2005.  In addition, new qualified gathering lines were not subject to alternative minimum tax.   

A natural gas gathering line was defined to include any pipe, equipment, and appurtenance that is

(1)     determined to be a gathering line by the Federal Energy Regulatory Commission, or

(2)     used to deliver natural gas from the wellhead or a common point to the point at which such gas first reaches

a.        a gas processing plant,

b.       an interconnection with an interstate transmission line,

c.        an interconnection with an intrastate transmission line,

d.       a direct interconnection with a local distribution company, a gas storage facility, or an industrial consumer. 

Status:  Gas gathering pipeline system assets should be classified, for depreciation purposes, as MACRS asset class life 13.2, Exploration for and Production of Petroleum and Natural Gas Deposits, and depreciated over 7-years.  The Technical Advisors recommend that examiners continue to verify that the alternative minimum tax computation on gathering lines placed in service prior to April 11, 2005 is being correctly computed.

The major tax issue regarding exploration cost in the oil and gas business is whether such cost is ordinary and necessary business expense or capital in nature. Generally, the distinction between capital expenditures and business expenses is made by looking to the extent and permanency of the benefit derived from the outlay. That is, an expenditure is considered capital in nature if it is for permanent improvements or betterment that increases the value of the property.  (Sec. 263(a) and Reg. Sec. 1.263(a)-1) Geological and geophysical exploration expenditures are made for the objective of acquiring and collecting information that will serve as a basis for the acquisition and retention of properties for purposes of oil and gas recovery or to reject an area as unworthy of development.

In recent years, there has been a steady shift in geophysical activity from conventional exploration to the development of known reservoirs. This shift has been caused by advancements in 3D and 4D technology. Taxpayers have begun to classify certain G&G costs as intangible drilling costs relating to either 1) determining the location to set an offshore producing platform and/or 2) determining well-site locations. This is currently one of the most contested areas between the Service and taxpayers. Although there is a broad difference from taxpayer to taxpayer on when it is proper to treat G&G as IDC, an aggressive interpretation is that all G&G acquired subsequent to obtaining the lease should be treated as IDC. Generally, the Service requires that the G&G project is tied to a specific well or wells and that the determination to drill such well must have been made prior to the G&G project for such project to qualify for IDC. If the project were of such scope as to delineate the entire structure, the Service generally would hold that the project was more in the nature of exploration and capitalize the costs to the leasehold account.

Prior to the enactment of new energy legislation noted below, the IRS position on geological and geophysical expenditures was Rev. Ruls. 77-188 and 83-105.

The Energy Policy Act of 2005 now permits G&G cost incurred in the United States to be amortized ratably over 24 months.  This 24-month amortization provision applies to all domestic exploration cost paid or incurred for tax years beginning after August 8, 2005.  If the property is abandoned, the remaining unamortized G&G must continue with its original 24-month amortization and cannot be expensed in the year of abandonment.    For all foreign exploration costs and those domestic exploration costs incurred in tax years beginning prior to August 8, 2005, the tax rules for handling G&G continue to be set forth in Revenue Rulings 77-188 and 83-105.

The G&G deduction for major integrated oil companies was further amended by the Tax Prevention and Reconciliation Act signed on May 17, 2006.  Major integrated oil companies are required to substitute 5 years for the 24 month amortization period.  A major integrated oil companies is described as a producer of crude oil

• which has an average daily worldwide production of crude oil of at least 500,000 barrels for the taxable year,
• which had gross receipts in excess of $1 billion for its last taxable year ending during calendar year 2005,
• and has an ownership interest of 15% or more in a refiner.

Issue: Whether amounts deducted by an individual on Schedule C or by a partnership for intangible drilling and development costs (IDC) under § 263(c) of the Internal Revenue Code    qualify to be currently deducted

Two factual patterns have emerged. First an individual is solicited to participate in an oil and gas venture. Typically the individual has no prior oil and gas experience. The materials from the promoter indicate the promoter has oil and or gas wells that they wish to develop. In exchange for contributing to the wells, the individual can claim an IDC deduction and at some point, an interest in the wells will be transferred to them. The individual sends a check to the promoter of the investment.

A review of the facts indicates that prior to the time of investment the wells had already been drilled by the promoter.

In the second pattern an individual is solicited and invests cash into a partnership. That is formed to acquire and drill oil and gas wells.

A review of the facts indicates that prior to the time of investment the wells had already been drilled by the promoter.

Treasury Reg. § 1.612-4 permits an "operator" (one who holds a working or other operating interest in an oil and gas property) to elect to deduct intangible drilling and development costs ("IDC") in the case of oil and gas wells, in lieu of capitalizing such costs.

The taxpayer must hold the interest when the IDC is incurred in order to elect to take a deduction. In these patterns the wells were already drilled and thus the IDC had already been incurred.

See Revenue Ruling 75-304.

U.S. taxpayers producing oil and gas outside the U.S. have been required since 1975 to characterize income as Foreign Oil and Gas Extraction (FOGEI) or Foreign Oil Related Income (FORI), and allocate foreign income taxes between these income sources.  The Tax Reduction Act of 1975 enacted Code section 907 and the FOGEI/FORI allocation requirement. 

FOGEI includes taxable income or loss derived from sources outside the U.S. and its possessions from the extraction of minerals from oil and gas wells, and the disposition of assets used by a taxpayer in the trade or business of extracting these minerals.  FOGEI is defined as the fair market value of the oil or gas in the vicinity of the well.  FORI includes taxable income or loss from the processing of oil or gas into their primary products, from the transportation or distribution and sale of oil and gas and their primary products, and from the disposition of assets used in these activities.

Section 907 was enacted to combat a theoretically simple problem.  Supposedly, the oil industry was generating excess foreign tax credits on FOGEI activities because foreign governments were disguising royalty payments as taxes. In drafting section 907, Congress was concerned with taxpayers’ ability to cover U.S. tax on other foreign activities (FORI and other Non-Oil Related Income (NORI)) normally taxed at a lower rate, with the high taxes on FOGEI.  Consequently, a special limitation on the amount of oil extraction taxes that could be claimed against  U.S. tax was enacted.  Section 907(a) seeks to prevent the excess foreign taxes on FOGEI from offsetting U.S. tax on other foreign source income.  The limitation imposed by section 907(a) is the maximum U.S. tax rate applied to a taxpayer’s FOGEI.  Since the limitation applies only to foreign taxes paid on extraction activities and not other oil related activities, the determination of FOGEI is important.

Since the enactment of Section 907 in 1975 Congress has made changes to section 907, but the statutory demarcation of FOGEI as taxable income from extraction and FORI as taxable income from processing, transportation and distribution has remained constant.

The separate limitation imposed by section 907(a) on the use of FOGEI taxes causes petroleum taxpayers to seek tax-planning opportunities to reduce the impact of this separate limitation.  All planning opportunities used by a taxpayer would have at their core a desire to move income and taxes out of FOGEI or to lower the effective tax rate on FOGEI.  These tax-planning opportunities can take a number of forms including:

Allocation To Transportation Income

An extraction or production company will allocate its income and taxes between FOGEI and FORI to recognize the income contribution from the transportation of crude oil from the wellhead (a FOGEI activity) to a port or distribution location (a FORI activity). This planning opportunity is desirable if the effective tax rate in the foreign country is high.  The allocation of income and taxes to FORI removes this highly taxed income from the impact of the separate section 907(a) limitation.

Unlike oil and gas production in the U.S., oil and gas produced overseas often must travel some distance through pipelines to a port or distribution facility.  The foreign government will establish a price for the oil and gas extracted within their country for purposes of calculating taxes to be paid in that country.  These prices are generally a port price that may not be comparable to the "fair market value" in the vicinity of the well.

In order to arrive at a price for determining FOGEI taxpayers will attempt to value the contribution of the pipeline or other transportation activity that moved the oil or gas from the wellhead to the port.  This valuation may be made using various formulas that impute value to the transportation assets (proportionate profits, rate of return on assets, etc.).  The valuation process used will be fact intensive, and the taxpayer must establish that the fair market value of the oil or gas in the vicinity of the well is different than the value at the port or distribution facility.  Usually the taxpayer will value the transportation assets and merely netback to obtain the value of the oil or gas at the wellhead.  A common sense reading of Section 907 and the applicable regulations indicates that the fair market value of the oil or gas should be determined first before trying to value the transportation element.    

Low Taxed FOGEI

Taxpayers will look for FOGEI that is not taxed by a foreign government or taxed at a low effective tax rate.  Through the identification of lightly taxed FOGEI an opportunity is presented to have this untaxed FOGEI absorb other FOGEI taxes on highly taxed income to minimize the impact of the section 907(a) limitation.  In evaluating a taxpayer's classification of income as FOGEI attention should be paid to FOGEI that is not heavily taxed to ensure it has be correctly classified.

Allocation of Expenses

The allocation of expenses under regulation 1.861-8 provides an avenue to allocate expenses away from FOGEI to other classes of foreign income.  If the allocation of expenses under regulation 1.861-8 is not performed correctly expenses that should be reducing FOGEI in the determination of taxable income can be shifted to reduce other foreign income thereby increasing FOGEI for U.S. tax purposes and lowering the effective foreign tax rate on this income.

Status:  On October 12, 2004, Field Directive on IRC § 907 Evaluating Taxpayer Methods of Determining Foreign Oil and Gas Extraction Income (FOGEI) and Foreign Oil Related Income (FORI).  This memorandum is intended to provide direction to effectively utilize resources in evaluating taxpayer methods of determining under IRC § 907 FOGEI and FORI income.  Agents are encouraged to obtain a copy of this memorandum from www.irs.gov or request a copy from the Technical Advisors.

Taxpayers are allowed to deduct Intangible Drilling Costs (IDC) even though they represent a capital investment.  IDC is normally limited to items such as labor, rig time, and services to drill and complete a well or construct on offshore drilling platform.  In recent years as producers have moved their offshore operations to deeper and deeper water depths, the use of subsea flowlines and umbilicals have become more common.  These assets connect remote wells which have their wellhead (aka christmas tree) on the seabed to a host platform.  Some taxpayers have been deducting as IDC the installation cost of these assets even though the well has already been drilled and completed, and is ready for its assigned purpose of producing oil and gas. 

This issue is usually limited to large oil and gas companies due to the size of the expenditures involved in subsea operations.  Due to the very technical nature of the issue, a referral should be made to obtain the assistance of an IRS petroleum engineers

AJCA § 302: Biodiesel Income Tax Credit

The Act creates Code Section 40A – Biodiesel Used as Fuel, providing an income tax credit reportable as a General Business Tax Credit for Biodiesel.  Biodiesel is an alternative fuel produced from domestic renewable resources; for example, soybean oil or recycled cooking oils.  Biodiesel contains no petroleum but can be blended with petroleum diesel into a biodiesel blend.  A common fuel blend would be 20% bodiesel/80% petroleum diesel.

There are two parts to determining the credit.  First, a credit of $.50/ gallon is allowed for each gallon of biodiesel used in the production of a qualified biodiesel blend that is sold by the taxpayer for use as a fuel or is used as a fuel by the producing taxpayer.  Second, a credit of $.50/gallon is allowed for each gallon of biodiesel not in a mixture which is used by the taxpayer as a fuel or is sold at retail by the taxpayer directly to the fuel tank of the customer.  The law raises the credit to $1.00/gallon if the biodiesel is agri-biodiesel (produced from first-use oils).  

Taxpayers must secure certification for the biodiesel from the producer or importer to claim a credit.  The biodiesel credit must be reduced by any excise   tax credit claimed under Code Section 6426 or 6427(e).  In general, if a credit is claimed and subsequently, any person separates the biodiesel or uses the mixture other than as a fuel there is a tax imposed on such person equal to the credit claimed.

AJCA § 338: Expensing of Capital Costs Incurred in Complying with EPA regulations.

The Act creates Code Section 179B – Deduction for Capital Costs Incurred in Complying with Environmental Protection Agency Sulfur Regulations.  The provision permits small business refiners (a taxpayer in the business of refining petroleum products who employs less than 1,500 employees and has less than 205,000 barrels per day (average) of total refining capacity) to claim an immediate deduction for up to 75 percent of the qualified costs paid or incurred when complying with EPA’s highway diesel fuel sulfur control requirements.  Qualified costs include expenditures for the construction of new process units or the dismantling and reconstruction of existing process units to be used in the production of low sulfur diesel fuel, associated adjacent or offsite equipment (including tankage, catalyst, and power supply), engineering, construction period interest, and sitework.  The percentage of costs allowed is reduced for amounts in excess of 155,000 barrels a day of total refinery capacity.

AJCA § 339: Credit for Production of Low Sulfur Diesel Fuel.

The Act creates Code Section 45H – Credit for Production of Low Sulfur Diesel Fuel.  The provision provides a general business credit to small business refiners equal to 5-cents for each gallon of low-sulfur diesel fuel produced during the taxable year that complies with EPA sulfur control requirements.  The total production credit claimed by the taxpayer cannot exceed 25% of the qualified cost incurred to comply with the EPA’s highway diesel fuel sulfur control requirements.  Basis in the property is reduced by the amount of credit claimed. To obtain the credit, the taxpayer will have to secure certification that the qualified costs will result in compliance with EPA regulations.

AJCA § 341: Oil and Gas From Marginal Wells

The Act creates Code Section 45I – Credit for Producing Oil and Gas from Marginal Wells.  The provision creates a new $3 per barrel credit for qualified crude oil production and 50 cents per 1,000 cubic feet of qualified natural gas production.  The term qualified production means domestic crude oil or natural gas produced from a qualified marginal well.  The credit is not available to production when the reference price of oil exceeds $18 and the price of natural gas exceeds $2.  The credit is reduced proportionately as the reference price ranges between $15 and $18 for crude oil and $1.67 and $2 for natural gas.  The credit will be treated as a general business credit.  In case of production from a qualified marginal well which is eligible for the credit allowed under section 29, no credit shall be allowed under this section unless the taxpayer elects not to claim the section 29 credit with respect to the well

AJCA § 706: Certain Alaska Natural Gas Pipeline Property Treated As 7-year Property.

This provision amends Section 168(e) (3) (C) (defining 7-year property) to include any Alaskanatural gas pipeline.  The term ‘Alaska natural gas pipeline’ includes the pipe, trunk line, related equipment, and appurtenances used to carry natural gas (but does not include any gas processing plant) located in the State of Alaska which has a capacity of 500 trillion Btu of natural gas per day and is placed in service after December 31, 2013.  If the system is placed in service prior to January 1, 2014, the taxpayer may elect to treat the system as placed in service on January 1, 2014 to qualify for the 7-year recovery period.  (If placed in service prior to January 1, 2014 and the election is not made, taxpayer would have a 15-year recovery period.  If elected, depreciation would not begin until after 2013.)

AJCA § 707: Extension of EOR Credit to Certain Alaska Facilities.

This provision amends Code Section 43(c)(1) (defining qualified enhanced oil recovery costs) by adding any amount paid or incurred during the taxable year to construct a gas treatment plant capable of processing two trillion Btus of Alaskan Natural Gas per day into a natural gas pipeline system.  To qualify, the gas treatment plant must also produce carbon dioxide for re-injection into a producing oil or gas field. 

WFTRA § 314: Taxable Income Limit On % Depletion for Oil and Gas From Marginal Wells.

The Act amended subparagraph (H) of section 613A(C) (6) extending the temporary suspension of taxable income limit with respect to marginal production through calendar year 2005 (December 31, 2005).  Without the amendment, the temporary suspension of taxable income limit with respect to marginal wells would not have been available for the 2004 tax returns

The President signed into law the Energy Policy Act of 2005 (P.L. 109-58) on August 8, 2005.  Income tax provisions affecting the domestic petroleum industry are summarized below:

EPA § 1323: Temporary Expensing for Equipment Used in Refining of Liquid Fuels

Primary Code Section 179C.  The new provision provides a temporary election to expense 50% of the cost of qualified refinery investments.  Any cost so treated is allowed as a deduction for the taxable year in which the qualified refinery property is placed in service.  The remaining 50% is recovered under present law. 

EPA  § 1325:  Natural Gas Distribution Lines Treated as 15-year Property

Primary Code Section 168(e)(3)(E)(viii),  The new legislation establishes a statutory 15-year recovery period (previously 20-years) and a class life of 35 years for distribution lines put in service after April 11, 2005.

EPA § 1326: Natural Gas Gathering Lines Treated as 7-year Property.

Primary Code Section 168(e)(3)(C)(iv).  The new legislation establishes a statutory seven-year recovery period and a class life of 14 years for natural gas gathering lines.  In addition, no adjustment will be made to the allowable amount of depreciation with respect to this property for purposes of computing a taxpayer’s alternative minimum taxable income. 

EPA § 1328: Determination of Small Refiner Exception to Oil Depletion Deduction.

  Primary Code Section 613A(d)(4).  The bill increases the current 50,000-barrel per day limitation to 75,000.  In addition, the bill changes the refinery limitation claiming independent status from a limit based on actual production to a limit based on average daily production for the taxable year. 

EPA § 1329: Amortization of Geological & Geophysical Expenditures.

Primary Code Section 167 (h).  The new legislation allows geological and geophysical costs amounts in connection with oil and gas exploration in the United States to be amortized over two years.  In the case of abandoned property, the remaining G&G basis may no longer be recovered in the year of abandonment of a property as all G&G basis is recovered over the two-year amortization period. 

EPA § 1346:  Renewable Diesel.

Primary Code Section 40A.  The Act amends Code Section 40A (relating to biodiesel used as fuel) by extending its provisions to renewable diesel.  It provides for an income tax credit reportable as a General Business Credit for renewable diesel used as a fuel in a trade or business, or sold at retail to another person and put in the fuel tank of that person’s vehicle.

The President signed HR 4297, Tax Increase Prevention and Reconciliation Act (TIPRA) of 2005 (P.L. 109-222), on May 17, 2006.  The income tax provision affecting the domestic petroleum industry is summarized below:

TIPRA § 503: 

5-Year Amortization on Geological And Geophysical Expenditures for Certain Major Integrated Oil Companies.

Primary Code Section 167(h).  Extends the two-year amortization period for G&G costs to five years for certain major integrated oil companies.  Applies only to integrated oil companies that have an avg. daily worldwide production of crude oil of at least 500,000 barrels for the taxable year, gross receipts in excess of $1 billion in the last taxable year ending during calendar year 2005, and an ownership interest in a crude oil refiner of 15 percent or more.

The President signed into law the Tax Relief And Health Care Act of 2006 (P.L. 109-342)) on December 20, 2006.  Income tax provisions affecting the domestic petroleum industry are summarized below:

TRHC § 118: Taxable Income Limit on Percentage Depletion for Oil and Natural Gas Produced From Marginal Properties

Primary Code Section 613A.  The provision extends for two years the present-law taxable income limitation suspension provision for marginal production (through taxable years beginning on or before December 31, 2007. 

On December 19, 2007, the President signed into law the “Energy Independence and Security Act of 2007 (P.L. 110-140).”  The income tax provision affecting the domestic petroleum industry is summarized below:

EISA § 1502: 7-year Amortization of G&G for Certain Major Integrated Oil Companies

Under pre-Energy Act law, major integrated oil companies amortized their geological and geophysical expenditures over five years (instead of the 24 month period that applied for other taxpayers). 

Effective for amounts paid or incurred after December 19, 2007, major integrated oil companies must amortize their geological and geophysical expenditures over seven years.  (Code Sec. 167 (h) (5), as amended by Energy Act § 1502.)  This provision applies only to integrated oil companies that have an avg. daily worldwide production of crude oil of at least 500,000 barrels for the taxable year, gross receipts in excess of $1 billion for its last taxable year ending during calendar year 2005, and an ownership interest in a crude oil refiner of 15 percent or more.  All other taxpayers will continue to amortize their geological and geophysical expense over a 24 month period.

On December 29, 2007, the President signed into law the “Tax Technical Corrections Act of 2007 (TTCA) (P.L. 110-172).”  The Act made technical and clerical corrections to certain provisions of the Internal Revenue Code of 1986.  The amendment related to the American Jobs Creation Act of 2004 (AJCA) affecting the domestic petroleum industry is summarized below:

TTCA § 7:   Interaction of rules relating to credit for low sulfur diesel fuel.

Small business refiners are allowed a tax credit for the production of low sulfur diesel fuel under Code Section 45H.  Revenue Procedure 2007-69 outlines the procedure under which small business refiners may obtain from the Service a certification that satisfies the certification of the costs related to a production facility.  (The TTCA redesigned the certification requirements from section 45H (f) to section 45H (e).)

Under AJCA Provision 339, Code Section 45H allowed a credit at the rate of 5 cents per gallon for low sulfur diesel fuel produced at certain small business refineries.  The aggregate credit with respect to any qualifying refinery was limited to 25% of the costs of the type deductible under Code section 179B.  Section 179B allowed a deduction for 75% of certain costs paid or incurred with respect to these refineries.  The basis of the property was reduced by the amount of any credit determined with respect to any expenditure (sec. 45H (d).  Further, no deduction was allowed for the expenses otherwise allowable as a deduction in the amount equal to the amount of credit under Code section 45H (sec. 280C (d).

TTCA amended provision 339.  Under the TTCA, deductions are denied in an amount equal to the amount of credit under section 45H, and the provisions of the AJCA reducing basis and denying a deduction are repealed.  

Taxpayers will need to file amended tax returns for prior returns affected by sections 179B and 45H to reflect the correct treatment. 

Effective Date:  The amendments are effective as if they had been originally included in the provisions of the American Jobs Creation Act of 2004 to which they relate.

29

Credit for Producing Fuel From A Nonconventional Source,

43

Enhanced Oil Recovery Credit

263(c)

Intangible Drilling Costs

263(a)

Geological and Geophysical expense needs to be capitalized. See Rev. Rul. 77-188 and 83-105.

263A

Carrying charges, such as delay rentals, are subject to capitalization under IRC § 263A.

611

Allowance of deduction for depletion.

612

Basis for Cost Depletion

613

Percentage Depletion

613A

Limitations on Percentage Depletion in Case of Oil & Gas Wells

614

Definition of Property

616

Development Expenditures

636

Income Tax Treatment of Mineral Production Payments

901

Tax creditability of levies where dual capacity taxpayer has received a specific economic benefit, generally with regard to natural resources.  Also, where tax laws modified for natural resources companies.

907

Determination of the amount and limitation of creditable taxes on income from foreign oil and gas extracted income (FOGEI).

954(g)

Income of a foreign controlled corporation not deferred if foreign base company oil related income.

Rev. Rul.      77-188

Tax treatment of geological and geophysical expenditures.

Rev. Rul.      83-105

The tax treatment of geological and geophysical expenditures under Rev. Rul. 77-108 is explained in 7 factual situations.

Rev. Proc.      87-56

Specifies class lives and recovery periods for property subject under the general depreciation system provided in IRC § 168(a) or the alternative depreciation system provided in IRC § 168(g).

Rev. Rul. 89-56

Which costs incurred in the course of fabricating, transporting, and installing an offshore oil and gas drilling and production platform and the related facilities and equipment are within the option to expense intangible drilling and development costs provided by section 263(c) of the Internal Revenue Code?

Notice 2006-61  (Published July 17, 2006)

This notice announces the applicable percentage under section 613A of the Code to be used in determining percentage depletion for marginal properties for the 1991-2006 calendar years.

Notice 2006-62 (Published July 17, 2006)

This notice contains the inflation adjustment factor and phase out amounts for the IRC §43 Enhanced Oil Recovery tax credit for the 1991-2006 calendar years.  (EOR credit for qualified cost paid or incurred in 2006 is completely phased out due to IRC Section 43(b)(3) inflation factor.)

Rev. Rul. 94-38

Environmental cleanup costs are capital costs for contamination done before the taxpayer bought the property but are deductible for contamination done by the taxpayer. Capital assets installed as part of the cleanup effort must be capitalized and depreciated.

Rev. Rul. 97-54

Recoverable line pack and cushion gas in natural gas pipelines are nondepreciable capital costs.  Effective for taxable years beginning after December 28, 1997.

Rev. Rul. 98-25

Under the circumstances described , the costs incurred to replace USTs containing waste by-products (including the cost of removing, cleaning, and disposing of the old USTs, and acquiring, installing, and filling the new USTs) are deductible by the taxpayer as ordinary and necessary business expenses under § 162.  Rev. Rul. 94-38 is distinguished.

Rev. Rul.   2000-7

The cost of removing an asset to replace it does not have to be capitalized under IRC §§ 263(a) or 263A as part of the cost of the replacement asset.

FERC Docket No. RM00-6-000; Order No. 616

FERC amended its regulations to reinstate provisions for well category determinations.

Rev. Rul.   2001-4

An airline may deduct the cost of heavy maintenance of its aircraft as an ordinary and necessary business expense, but must capitalize the cost of improvements that materially add to an aircraft’s value or prolong its useful life.

Rev. Rul.   2001-8

Payments made or received with respect to floor stocks must be accounted for as adjustments to the invoice price or production cost of the goods physically held on the floor stocks date to which the payments relate.

Rev. Proc. 2002-41

Provides that employers in the pipeline construction industry may use an optional expense substantiation rule to provide reimbursements under an accountable plan to employees who also furnish welding rigs or mechanics rigs as a condition of employment and use those rigs in their performance of services as employees.

Rev. Rul.  2003-37

Describes documentation, information and procedures for taxpayers that use the fair market value method of apportionment of interest expense for determining taxable income attributable to gross income from foreign sources.

Rev. Rul.  2003-54

Service ruled that gasoline pump canopies that are used at most retail outlets are not inherently permanent structures and are thus classified as tangible personal property.  However, the supporting concrete footings are inherently permanent structures that should be classified as land improvements for depreciation purposes.

Rev. Rul   2003-82

Service ruled that both costs of acquiring tertiary injectants as well as the costs of using tertiary injectants are eligible for the enhanced oil recovery credit provided in § 43.

Rev. Rul.  2004-17

Amounts paid or incurred in the current taxable year to remediate environmental contamination that occurred in prior taxable years do not qualify for treatment under § 1341.

Rev. Rul.  2004-18

Environmental remediation costs are subject to capitalization under §263A.  Therefore, costs incurred (within the meaning of IRC §461(h) and reg §1.263A-1(c)(2)(ii)) to clean up land that a taxpayer contaminated with hazardous waste by the operation of the taxpayer's manufacturing plant must be included in inventory costs under §263A.  Clarifies Rev. Ruls. 94-38 and 98-25.

Rev. Proc. 2004-19

Provides an elective safe harbor that the owner of domestic oil and/or gas properties may use in determining the property’s recoverable reserves for purposes of computing cost depletion under § 611 of the Internal Revenue Code.

TD 9168

This document contains final regulations relating to the optional 10- year write-off of certain tax preference items under section 59(e) of the Internal Revenue Code (Code).

T.D. 9263

This document contains final regulations concerning the deduction for income attributable to domestic production activities under section 199 of the Internal Revenue Code.

Texaco, Inc. v. United States, 528 F.3d 703 (9^th Cir. 2008)

Ninth Circuit followed Pennzoil-Quaker State appellate decision and concluded that payments made to Department of Energy for violations of crude oil pricing were barred from relief under section 1341 by the inventory exception of section 1341(b) (2).

Pennzoil-Quaker State v. United States, 511 F.3d 1365 (Fed. Cir. 2008)

Federal Circuit reversed Court of Federal Claims and concluded that antitrust settlement payments were barred from relief under section 1341 by the inventory exception of section 1341(b)(2).

Pennzoil-Quaker State vs. Comm., 62 FED.Cl 689

Court concluded that antitrust settlement payments satisfied the elements of § 1341(a) and not barred by the inventory exception.  

Reversed on appeal.  See case above.

PDV America v. Commissioner, T.C. Memo 2004-118

Court held that above ground storage tanks were not inherently permanent structures and qualified as 5-year property under MACRS Asset Class 57.0 rather than as 15-year property under MACRS Asset Class 57.1.  (See page 24 for status of issue.) 

Clajon Gas Co., v. Comm.., 354 F3d 786

Eighth Circuit Court of Appeals reversed the Tax Court, 119 T.C. 197, and held that gathering systems were production assets, subject to a seven-year depreciation period.

Saginaw Bay Pipeline v. United States, 338 F.3d 600

Sixth Circuit Court of Appeals reversed the United States District Court for the Eastern District of Michigan ruling, 88 A.F.T.R.2d 2001-6019, and held that every natural gas pipeline which functions as a “gathering pipeline” in the methane gas production process by transporting raw natural gas from the field wellheads to a cleansing processing facility qualifies as a “gathering pipeline” subject to a seven-year life, irrespective of the primary business of the owner of that pipeline.

Erickson Post Acquisition, Inc. v. Comm. TC Memo. 2003-218

Tax Court held that advance from oil company was a loan, and not gross income to service station owner/operator.  (See page 26 for explanation and status of issue.  The Commissioner announced nonacquiescence in 2006-24 I.RB. 1039.

Exxon Mobil v. United States, 253 F. Supp.2d 915 (N.D.Tex. 2003)

Percentage depletion was not allowed with regard to two natural gas contracts. The taxpayer failed to prove that the contracts   would qualify as “fixed contracts.”  

Iowa 80 Group v. United States, 203 F.Supp.2d 1058

The Court held that a “retail motor fuels outlet” could not encompass several buildings for purposes of § 168.

Shell Petroleum v. United States, 50 Fed.Cl. 524

The Court held that Shell failed to show that they used enhanced oil recovery techniques prior to  April 2, 1980, and the oil could not have been produced from tar sands under the § 29 tax credit.

HB&R Inc. v. United States, 86 AFTR2d 2000-5383

A company is not liable for FICA tax withholding on any part of airline tickets provided employees for commuting between their work site and their homes.

Exxon Mobil Corp. v. Commissioner, 114 T.C. 293 (2000)

Estimated dismantlement, removal, and restoration (DRR) costs for oil production equipment in Prudhoe Bay is not fixed and determinable enough to be accruable under the all-events test of IRC §1.461-(a)(2).

Exxon Corp. v. United States, 84 AFTR 2d ¶99-5588, 2000-1 USTC ¶50,116

Representative market or field price for oil transported away from premises before being sold may exceed actual sale price.

AOD CC-1999-017

Service issued nonacquiescence to Duke Energy Natural Gas Corp. v. Commissioner, 172 F.3d 1255 (10^th Cir., 1999)

Exxon Corp. v. Comm. 113 T.C. No. 24

U.K. Petroleum Revenue Tax ruled creditable because it was not paid for specific economic benefits.

Duke Energy Natural Gas Corporation v. Commissioner, 172 F.3d 1255 (10^th Cir. 1999).

The 10^th Circuit Court of Appeals reversed the Tax Court decision , 119 TC 416, and ruled that gathering systems were assets used in exploration  for and production of petroleum and natural gas deposits, and could be depreciated over seven years pursuant to Asset Class 13.2  under MACRS.

Texasgulf, Inc. v. U.S. Fed. Cl.,83 AFTR 2d 1784 CA2, affg. 107 TC 51, 84 AFTR 2d ¶99-5433, 99-2 USTC ¶50,915

Ontario Mining Tax ruled creditable because it satisfies the net income requirement of '901.

True Oil Co. v. Comm., 83 AFTR2d Par. 99-537; No. 97-9029

The Tenth Circuit affirmed a Tax Court decision holding that a well-category determination under section 503 of the Natural Gas Policy Act of 1978 is a prerequisite to obtaining the IRC § 29(a) tax credit for gas produced from a tight formation.

Union Texas International Corporation v.Commissioner 110 TC 321.

The Tax Court recognized the agency relationship between two subsidiaries preserving the independent producer status of one of the subsidiaries.

Amoco Corp. v. Commissioner, 138 F3rd 1139 (CA 7)

The 7^th Circuit Court of Appeals ruled that Egyptian tax creditable since a compulsory tax not refunded and not a subsidy.

Mary Herbel v. Commissioner, 80AFTR2d 97-5655 CA 5.

Take or pay settlement payment is income to the recipient in the year received.

Texaco Inc. et al. v Commissioner

98 F3d 825 (5^th Cir. 1996)

No IRC § 482 reallocation of crude oil pricing income for the “Aramco Advantage”. Saudi law controlled Texaco and Exxon Prices.

Phillips Petroleum Co. v. Commissioner, 101 T.C. 78 (1993),

Income from the sale of Alaskan liquefied natural gas to Japan was sourced as part foreign.

Shell Oil Company v. Commissioner, 952 F.2d 885

Overhead must be allocated to (IDC) in capitalizing IDC and in calculating percentage depletion.

Whiteco Indus. v. Comm., 65 T.C. 664.

Court held that outdoor advertising signs constitute ‘tangible personal property’ within the meaning of § 48(a) (1) (A).

TAM 9602002

Delay rentals are a preproduction cost and must be capitalized under §263A.

PLR 9641003

Airplane tickets for employee’s returns home furnished by employer are wages subject to Federal Income Tax withholding, FICA, and FUTA.

TAM 9644002

Wells producing gas from tight formations before 1993 do not qualify for the §29 tax credit unless the producer obtained FERC certification.

PLR 9752026

Following a reorganization, allowed independent producer status to one subsidiary of a consolidated oil company.

PLR 9848003

A taxpayer may not modify the amount capitalized and amortized under section 59(e) without first obtaining permission from the Secretary to revoke the original election.

PLR 199912010

For purposes of regulation §1.903-1, provides an example of a tax that qualifies as a tax “in lieu of income taxes.”

FSA 199949016

The Service clarified how MACRS depreciation asset classifications apply to an oil refinery’s assets. (Refinery vs. Chemical)

PLR 200103009

Attribution of the §29 nonconventional fuels credit among the parties to a transaction involving a production payment.

IRS CCA 200146052

Advised the NRC Industry Director that a taxpayer had withdrawn its PLR request regarding the classification of sulfur removal equipment at a natural gas processing plant.  Concluded that such equipment belonged in Asset Class 49.23 (Natural Gas Production Plant) not Asset Class 28.0 (Chemical Manufacturing).

FSA 200206038

Depreciable assets used by a company for it drilling fluids business are includible in MACRS asset class 28.0.

FSA 200221016

Service ruled that vessels that are chartered during the tax year to multiple time charters engaged in different business activities are classified in accordance with the business activity in which they were primarily used during the year.

FSA 200216030

Service ruled that an oil and gas producer should classify an offshore drilling platform under MACRS asset class 13.2 for depreciation purposes rather than under asset class 13.0.

TAM 200252029

Natural gas liquids that are removed from a gas stream in a gas plant before the gas is first sold, are not eligible for the section 29 credit as "gas produced from a tight formation."

PLR 200311003

Service rules that floating (self-propelled) platform assets owned and operated by integrated oil producers should be classified as seven-year property under Asset Class 13.2 for depreciation purposes, rather than as five-year property under Asset Class 13.0.

PLR 200308001

Where there is no representative market or field price available, then the RMFP will equal the gross income from the property for purposes of the depletion allowance.  In the absence of an RMFP, and an alternative method is used to determine the gross income from the property for depletion purposes, the GIFP should be determined by reference to income actually received.

PLR 200227002

Service ruled that the vaporization of relict oil and condensate in the apex and immobile oil and condensate in the portion of the expanded gas cap unswept by the cyclic gas injection is a qualified tertiary recovery project pursuant to § 43 and the regulations thereunder.

IRS NSAR 20044101F

Service ruled that a crude oil gathering system’s pipeline is considered like-kind under IRC § 1031 if exchanged for property in the same general asset class or product class if the pipeline is deemed personal property under state law.

PLR200503003

For purposes of IRC §§613A and 291(b), made several conclusions regarding the open pit mining of a tar sand deposit and the subsequent upgrading, and refining of the extracted material into a liquid hydrocarbon.

PLR 200535028

Ruled the Taxpayer has not established that it had increased its expected ultimate recovery due to the recovery of oil from substantially unaffected reservoir volume, the Taxpayer's post-1990 activities on its pre-1991 project area do not constitute a significant expansion of the project under  Treasury Regulation section 1.43-2(d)(2).

TAM 200629031

Concluded that assets used within a taxpayer’s highly integrated refinery to primarily produce refinery products belong in Asset Class 13.3 (Petroleum Refining), not Asset Class 28.0 (Manufacture of Chemicals and Allied Product).