Until recently, surging crude oil and petroleum product prices combined with growing demand had caused oil and gas companies to achieve record revenues and profits for themselves and their investors worldwide. It is little surprise that many companies in this industry are seeing more inquiries from the Internal Revenue Service ("IRS" or the "Service") and the states.

In assisting oil and gas companies with these inquiries, we have noted several common areas of interest. This tax flash highlights some issues companies should anticipate in upcoming examinations. As a brief review, the Large and Mid-Size Business ("LMSB") Division of the IRS serves corporations, subchapter S corporations, and partnerships with assets greater than $10 million.

LMSB covers five industries and one examination support function.

• Communications, Technology, and Media
• Financial Services
• Heavy Manufacturing and Transportation
• Natural Resources and Construction
• Retailers, Food, Pharmaceuticals and Healthcare

A major objective of the LMSB Division's Issue Management Strategy is to identify, coordinate and resolve complex and significant industry wide issues by providing guidance to field examiners and ensuring uniform application of the law through the issuance of coordinated issue papers. Although these papers are not official pronouncements on the issues, they do set forth the Service's current thinking.

In addition to coordinated issue papers, LMSB adopted an issue tiering strategy in 2006 to ensure that high-risk compliance issues were properly addressed and treated consistently across the division for all LMSB taxpayers that are affected by the issue. Compliance issues are identified by the Field through examinations, Schedule M-3 reviews, and other sources. Industry Directors, working with their industry issue coordinators, evaluate the compliance issues identified in the Field and elevate those deemed most significant as potential Tier I, II, or III issues.

• Tier I issues are of high strategic importance to LMSB and have significant impact on one or more Industries. Tier I issues could include areas involving a large number of taxpayers, significant dollar risk, substantial compliance risk or high visibility, where there are established legal positions and/or LMSB direction. Tier I includes recognized abusive and listed transactions as well as other "high-risk" transactions and issues that represent LMSB’s highest compliance priorities. LMSB requires that the Issue Owner Executive (someone assigned to have responsibility for overseeing the identification of the issue, developing an IRS position, and coordinating on disposition or resolution) have oversight and control over Tier I issues.
• Tier II issues reflect areas of potential high non-compliance and/or significant compliance risk to LMSB or an Industry. Tier II includes emerging issues, where the law is fairly well established, but there is a need for further development, clarification, direction and guidance on LMSB’s position. Tier II issues require "coordination" with the Issue Owner Executive.
• Tier III issues are those issues that represent the highest compliance risk for a particular industry and which require unique treatment for an industry. The examination process of Tier III issues generally follows traditional examination procedures.

Even though the issues discussed below may not result in material tax dollar deficiencies (or benefits), they may require considerable time resources to resolve. If certain issues require additional time and resources, the IRS will often still require resolution of the issue since other taxpayers have incurred the necessary time and resources to resolve the issues to the IRS’s satisfaction. The IRS will highlight that one of their goals has been to promote consistent treatment of taxpayers.

There are two issues with respect to recoverable reserves. First, it is the IRS’s position that a 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 proved reserves (developed and undeveloped) and, under appropriate circumstances, additional reserves. "Additional Reserves" will most often include "probable and prospective" reserves.

To address this issue, the IRS issued Revenue Procedure 2004-19 on March 8, 2004. 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. Under the safe harbor, the total recoverable units is estimated to equal 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 end of the respective taxable year.

The second issue with respect to recoverable reserves is whether a taxpayer is permitted to revise the original reserve estimate based solely on changes in economic factors. It is the IRS’s position that 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.

Note: Taxpayers should consider whether to utilize the safe harbor in order to avoid complex and time consuming arguments as to what constitutes the appropriate quantity of "Additional Reserves", especially in cases where a taxpayer identifies probable and prospective reserves for investors or other reasons. In cases where a taxpayer has not elected the safe harbor and is under audit, active discussions with the examiner and the petroleum engineer should be considered to explore the use of the safe harbor, retroactively.

Although not addressed in the coordinated issue, it is common for the depletion calculations to be examined to challenge the proper "unit-of-property", as defined in § 614 of the Internal Revenue Code. Regulation § 1.611-1(d)(1) defines "property" as (i) in the case of minerals, each separate economic interest owned in each mineral deposit in each separate tract or parcel of land or an aggregation or combination of such mineral interests permitted under § 614(b), (c), (d) or (e). It is not uncommon to discover that a taxpayer has not determined the proper "unit-of-property" for use in their tax depletion calculations as some taxpayers determine their tax depletion at the well level or at a field level. In such cases, a taxpayer under audit should expect to incur considerable time determining the proper "unit-of-property" and recalculate depletion in order to get an examiner comfortable with the tax depletion taken on a tax return.

In addition, the required method for determining reserves is to use the end of year reserves and add production for the year. This will often result in a difference from the reserves, as reflected at the beginning of the year in a separate reserve report.

Note: The SEC recently approved changes to its reporting requirements for oil and gas producers that allow the use of technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new rules also will allow companies to disclose their probable and possible reserves to investors. Unfortunately, these disclosures will likely result in a larger reserve base in the IRS’s eyes and encourage at least some taxpayers to consider the safe harbor election. However, because the safe harbor provided by the IRS incorporates the SEC’s definition of proved reserves, taxpayers will still likely face a significant reduction in their yearly tax depletion deductions in either scenario.

It is the IRS’s position that 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. Further, it is the IRS’s presumption that taxpayers in the business of producing oil and gas acquire leasehold interests with the intent to develop them and will use the fact that a taxpayer has performed geological and geophysical surveys ("G&G") on acquired leaseholds or has filed a plan of development with an appropriate governmental agency as demonstrating an unequivocal intention to develop the leasehold in the future.

The Energy Policy Act of 2005 mandated that G&G costs incurred in the United States be amortized ratably over 24 months using a half-year convention. This effectively results in a three-year amortization period since 25% (6 months) is taken in year one, 50% (12 months) in year two and the remaining 25% (6 months) in year three. This 24-month amortization provision applies to all domestic exploration costs 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.

The G&G deduction is extended futher for major integrated oil companies, which are defined as producers 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.

Note: The IRS’s Oil and Gas Industry Market Segment Specialization Program instructs examiners to inspect "other deductions", including "other professional expenses", carefully to identify such items as G&G expenses that have been incorrectly deducted, instead of capitalized and amortized over the required period of time. Taxpayers should take steps to insure that they have properly captured all of their G&G costs and have followed the required 25/50/25% amortization periods.

DPD, or Section 199, is a provision enacted in the American Jobs Creation Act of 2004 that generally allows taxpayers to receive a deduction based on qualified production activities (including oil and gas extraction) income resulting from domestic production (or taxable income, if it is lower). In the initial years, 2005 and 2006, the deduction was 3% moving to 6% from 2007 to 2009 and then 9% thereafter. However, there is a limit for taxpayers with oil related production income for tax years after 2009 that reduces their benefit to 6 percent.

The Section 199 deduction is limited to 50% of a taxpayer’s W-2 wages. W-2 wages for purposes of determining the Sec. 199 wage limitation amount includes only amounts that are properly allocable to domestic production gross receipts (oil and gas extraction income in this case).

Note: A taxpayer that has claimed the benefit of the DPD should be prepared to provide the workpapers and calculations used to determine their benefit for the year under examination. At a minimum, an examiner will generally perform the following checks on the DPD deduction:

1. Evaluate whether the taxpayer’s business makes sense with the activity requirements of the DPD. In this step, they will likely review a taxpayer’s website and annual report as well as require an explanation from the taxpayer.
2. Compare the domestic production gross receipts reported on Form 8903 to the gross receipts or sales less returns and allowances on the taxpayer’s tax return.
3. Determine whether the taxpayer is required to allocate gross receipts, to remove nonqualified embedded service income, or determine the qualified income portion of a component of an item and evaluate a taxpayer’s method of doing so, if it applies.
4. Determine whether the taxpayer was required to allocate and apportion deductions and used an appropriate and consistent method.
5. Evaluate whether the taxpayer has applied the wage and taxable income limitations.

Given the decline in prices, many oil and gas companies are projecting tax losses for the near future. Any resulting net operating loss carryback or carryforward would reduce a taxpayer’s taxable income and possibly limit their DPD as a result. Taxpayers in this situation should consider the resulting impact on the DPD in their decision to carry back the net operating loss or carry it forward. Further, any taxpayers that limited their DPD as a result of a taxable income limit should consider the benefit from an increased DPD as a result of any IRS adjustments that increase their taxable income.

The IRS’s concern here is what they see as a growing trend in the utilities and telecommunications industry whereby taxpayers are deducting casualty losses under IRC Section 165 and then deducting the cost of restoring the damaged property as repair expenses under Section 162.

A corollary issue relates to the adjusted basis of the assets used in calculating the allowable casualty loss amount. In applying Regulation Section 1.165-7, which limits the deduction to the taxpayer's basis in the SIP damaged or destroyed, taxpayers have designated as the SIP their entire utilities transmission and distribution system or their entire telecommunication system.

As to the first issue, the Service's position is that the taxpayer cannot take both a casualty loss deduction and a business repair expense deduction as a result of one casualty. Rather, the casualty loss is deductible under IRC Section 165 and the cost of restoring the property to its pre-casualty condition must be capitalized under IRC Section 263.

As to the corollary issue, business casualty loss deductions are limited to the lesser of (a) the difference between the fair market value of the property before and after the casualty or (b) the adjusted tax basis of the property immediately before the casualty; if the property is destroyed, in effect only the basis limit applies. The deduction limits are determined by reference to the value and basis of the SIP damaged or destroyed. Because taxpayers’ damaged or destroyed properties have been subject to accelerated write-offs and may have been in service for significant periods of time, taxpayers often have a low tax basis in these assets. It is the IRS’s position that by defining as the SIP their entire transmission and distribution system or telecommunications system, not the specific assets damaged or destroyed, the taxpayers have a larger cost basis in computing their casualty loss deduction.

Note: Although this Tier II issue has been identified in the utilities and telecommunications industry, we have seen the issue addressed in oil and gas company IRS examinations where taxpayers were impacted by hurricanes or other casualties in the years under audit and the IRS has raised the same issues addressed above.

Understanding the rationales and goals of the IRS with respect to these issues will provide taxpayers insight into their approach to develop a strategy and defense, understand the documentation the IRS will demand and identify areas of exposure.

For more information, please contact Duane Snyder, Tax Partner, at dsnyder@heincpa.com or 972-458-2296.

Footnotes:
1. In addition to the Cost Depletion and Capitalization of Delay Rental Issues mentioned, the IRS has coordinated issues for North Sea IDC Transition Rules and Underground Storage Tanks at Gasoline Retail Locations.
2. Also designated as a Tier III issue for the industry.
3. Other tier issues common to the petroleum industry but not discussed here are the enhanced oil recovery credit (Tier II issue) and the expensing of environmental remediation costs (commonly referred to as the Federal Brownfield Tax Incentive)(Tier III issue).

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