Oil and Natural Gas Industry Tax Issues in the FY2014 Budget Proposal
Released: 2013-10-30T00:00:00

Background

The Obama Administration, in the FY2014 budget proposal, has proposed eliminating a variety of federal tax deductions and credits available to the oil and natural gas industries. This year's proposals are similar to those sent to Congress in conjunction with the FY2010 through FY2013 budget requests. New revenue estimates for the FY2014 proposed tax changes are $40.7 billion over the next decade, contrasted with decade estimates of $38.6 billion in 2013, $43.6 billion in 2012, $36 billion in 2011, and $31 billion in 2010, for essentially the same proposed changes. Although Congress did not implement these proposals in previous years, they might be considered as part of long-run deficit reduction agreement.

The Administration characterizes the deductions and credits slated for elimination as tax preferences, or oil and gas industry subsidies, that are costly to U.S. taxpayers and do little to either provide incentives for increased production or reduce prices to consumers. A contrasting description is provided by the American Petroleum Institute (API), which describes the tax provisions slated for elimination as "standard business deductions (some available to all other industries) and mechanisms of cost recovery—a fundamental and necessary component to a national income tax system."

The Administration also characterizes repealing these tax preferences as eliminating market distortions, and links them to providing resources for investments in clean, renewable, efficient energy resources.

The FY2014 Budget Proposal

The Administration's proposals to foster a clean energy economy and reduce consumption of fossil fuels have led to eight proposed tax changes for the oil and natural gas industries. Table 1 identifies the proposed tax changes and the Administration's estimates of the revenue gains for 2014, the five year period FY2014-FY2018, and the 10-year period FY2014-FY2023.

Many of these proposed tax changes have the effect of equalizing the tax treatment of independent oil producers to that of the major oil companies. Equalization is accomplished by eliminating preferential tax treatment of the independent companies not available to the major oil companies. In some cases, for example, the expensing of intangible drilling expenses, the major oil companies have been excluded from the benefits of the tax provision for years, while the independent companies continue to receive the benefit.

As shown in Table 1 , the proposed tax changes would have the effect of raising an estimated $3.9 billion in FY2014. Almost all (96%) of the revenues from the proposed tax preference repeal from FY2014-FY2023 would come from only three of the proposals, while two of the proposals would provide no revenue at all.

Compared to the FY2013 budget proposal, the current proposal estimates less revenue received in the current year, $3.9 billion compared to $4.8 billion, but higher revenues over the 10-year period, $40.7 billion compared to $38.6 billion. The major difference in the revenue estimates comes from a revision of the revenue gains from repealing the domestic manufacturing deduction for the oil and natural gas industries. That provision was expected to yield $11.6 billion over the 10-year time horizon in 2013, compared to $17.4 billion in the current estimate. In addition, the repeal of the expensing of intangible drilling expenses provision is expected to yield $11 billion in the 2014 proposal, compared to $13.9 billion in the 2013 budget proposal.

Repeal Enhanced Oil Recovery Credit

The enhanced oil recovery credit provides for a credit of 15% of allowable costs associated with the use of oil recovery technologies, including the injection of carbon dioxide, to supplement natural well pressure, which can enhance production from older wells. The credit is only available during periods of low oil prices, determined by yearly guidance with respect to what constitutes a low price. The credit has not been in effect over the past several years. Elimination of this credit would likely not have any effect on current, or expected, oil production, as oil prices are generally expected to remain high. Periods of low oil prices are usually associated with excess supply in the market. During periods of excess supply, it is unlikely that keeping older, higher-cost, low-production wells producing is an effective strategy for oil companies. Revenues from these wells are unlikely to cover operating costs in periods of low prices, although the credit could provide the margin that keeps some of these wells in production.

Repeal Credit for Oil and Gas from Marginal Wells4

The marginal well tax credit was implemented as the result of a recommendation by the National Petroleum Council in 1994. The purpose was to keep low-production oil and natural gas wells in production during periods of low prices for those fuels. The tax credit is designed to maximize U.S. production levels even when energy markets result in low world prices for oil, and low regional prices for natural gas. It is believed that up to 20% of U.S. oil production and 12% of natural gas production might be sourced from wells of this category. The credit was enacted in 2004, but has not been utilized because market prices have been high enough since that time to justify production on economic grounds without the application of the credit. The credit is not likely to be an important factor if prices remain high, or if the United States is successful in transitioning to alternative energy sources. The high-cost wells that fall into the marginal well category are likely to be some of the first eliminated on economic efficiency grounds if a reduction in petroleum prices occurs even if the credit were maintained.

Repeal Expensing of Intangible Drilling Costs

The expensing of intangible drilling costs has been part of the federal tax code since 1913. Intangible drilling costs generally include cost items that have no salvage value, but are necessary for the drilling of an exploratory well, or the development of a well for production. Intangible drilling costs cover a wide range of activities and physical supplies, including ground clearing, draining, surveying, wages, repairs, supplies, drilling mud, chemicals, and cement required to commence drilling, or to prepare for development of a well. The purpose of allowing current-year expensing of these costs is to attract capital to what has historically been a highly risky investment. Current expensing allows for a quicker return of invested funds through reduced tax payments.

In recent years, the risk associated with finding oil has been reduced, but not eliminated, through the use of advanced technology, including three-dimensional seismic analysis and advanced horizontal drilling techniques, among others. These advances make expensive "dry holes" less likely, and expand the physical range of exploration and production activities available from a drilling rig, reducing the cost of exploration of prospective oil and natural gas fields.

In the current law, the full expensing of intangible drilling costs is available to independent oil producers. Since 1986, major integrated oil companies have been able to expense 70% of their intangible drilling costs and capitalize the remaining 30% over a 60-month period. The FY2014 budget proposal would repeal both direct expensing and the accelerated capitalization provision, and replace them with generally applicable accounting procedures for cost recovery.

Administration estimates are that the repeal of the expensing of intangible drilling costs provision will yield $10.9 billion in revenue over the decade to 2023. In response to a similar tax proposal in the FY2010 federal budget proposal, the Independent Petroleum Association of America (IPAA) estimated that the tax change would result in an initial year reduction in investment in U.S. oil development of about $3 billion. IPAA's estimated reduction in oil development spending implied an almost dollar-for-dollar relationship between higher taxes and reduced investment. Little empirical evidence for the estimate was provided. The effect of the elimination of the expensing of intangible drilling costs in FY2012 was estimated by IPAA to result in an almost immediate one-third reduction in drilling budgets.

Actual reductions in drilling budgets are likely to be determined by the effect of increased taxes in conjunction with the price of oil. If the price of oil were to settle in the $40-per-barrel range that prevailed in December 2008, the burden of additional tax expense on the independent firms could reduce drilling activity. The combination of low oil prices and additional taxes might not justify the development of relatively high-cost resources, especially in deep waters, as in the Gulf of Mexico. However, with the October 2013 price of oil around $100 per barrel, reflecting political unrest in the Middle East as well as other factors, the additional tax expense is likely to have a smaller effect on reducing oil development activity.

Repeal Tertiary Injectants Deduction

Tertiary injection expenses, including the injectant cost, can be fully deducted in the current tax year. Supporters of the favorable current treatment of these expenses point to the importance of tertiary recovery methods in maintaining the output of older wells, as well as the environmental advantages of injecting carbon dioxide, a primary tertiary injectant, into wells. Repeal of the deduction, or less favorable tax treatment of the expenses, would be likely to reduce oil output from older producing fields during periods when the profit margin, and the price of oil, is low. During a period of high oil prices, the repeal is likely to have a smaller effect on production levels.

Repeal Passive Loss Exception for Working Interests in Oil Properties

Repeal of the passive loss exception for working interests in oil and natural gas properties is a relatively small item in terms of tax revenues, estimated at $74 million from FY2014 to FY2023. The provision exempts working interests, investments, in gas and oil exploration and development from being categorized as "passive income (or loss)" with respect to the Tax Reform Act of 1986. This categorization permits the deduction of losses accrued in oil and gas projects against other active income earned without limitation, and is believed to act as an incentive to induce investors to finance oil and gas projects.

Repeal Percentage Depletion Allowance

Percentage depletion is the practice of deducting from an oil company's gross income a percentage value, in the current law 15%, which represents, for accounting and tax purposes, the total value of the oil deposit that was extracted in the tax year. Percentage depletion has a long history in the tax treatment of the oil industry, dating back to 1926. The purpose of the percentage depletion allowance is to provide an analog to normal business depreciation of assets for the oil industry, in effect equating the tax treatment of oil deposits to the tax treatment of capital equipment in more traditional manufacturing industries. The analogy is based on the observation that both capital equipment in traditional manufacturing, as well as an oil deposit, are "wasting resources" in the sense that they both require capital investment to generate an income stream, and that both will eventually become nonproductive through obsolescence or through wearing out. Depreciation allowances are applied against the investment in capital equipment, and depletion allowances are applied to the value of oil deposits as a way to recover initial investments.

In its current form, the allowance is limited to domestic U.S. production by independent producers, on the first 1,000 barrels per day, per well, of production, and is limited to 65% of the producer's net income.

Percentage depletion was eliminated for the major oil companies in 1975. Although major oil companies' profits were likely affected by the tax change, their production of oil showed little variation as a result. Production of oil within the United States remains attractive for companies because ownership of the oil is allowed in this country. In most areas of the world, ownership of oil is vested in the national oil company, as a proxy for the state itself. The result is generally a lower share of revenues for private oil companies producing outside the United States. The Administration projects that the repeal of the percentage depletion allowance would yield tax revenues of approximately $10.7 billion over the period FY2014 through FY2023.

Repeal Manufacturing Tax Deduction (§199)

A provision in the proposed budget for FY2014 that affects both independent and the major companies' oil and natural gas tax liability is the repeal of the domestic manufacturing tax deduction for those industries. As shown in Table 1 , the Administration estimates that the repeal of this deduction for the oil and natural gas industries would contribute $1.1 billion in revenue in 2014, $8.8 billion for the period FY2014 to FY2018. The total increase in tax revenue is estimated to be $17.4 billion from FY2014 to FY2024, according to estimates reported in the budget proposal.

This tax provision was enacted in 2004 as part of the American Jobs Creation Act ( P.L. 108-357 ) to encourage the expansion of American employment in manufacturing. The oil industry was categorized as a manufacturing industry, and hence, eligible for the deduction, which was to be phased in over several years, beginning at 3% in 2005, and rising to a maximum of 9% in 2010. The base of the tax is net income from domestic manufacturing activities, capped by a limitation related to the size of the company's payroll. Section 199(d)(9) of the Tax Code limits the rate available to the oil and natural gas industries to 6%.

This tax deduction was intended to provide domestic firms an incentive to increase domestic employment in manufacturing at a time when there was concern that manufacturing jobs were migrating overseas. By allowing a percent deduction of net income, up to the payroll limitation, the effective cost of labor to the manufacturer was reduced. The reduction in net labor cost was intended to expand employment, increase output, and reduce prices, making domestically manufactured goods more competitive in the U.S. and world markets.

Although the oil and natural gas industries are classified as manufacturing industries for data reporting and tax purposes, they differ from traditional factory manufacturing in a number of ways. For example, the production of petroleum products at a refinery is only indirectly related to the level of employment. This implies that if wage costs go down due to the tax deduction, there is less chance that the result will be increased output due to higher employment. Even if employment did increase, it would have little effect on national employment levels due to the capital-intensive nature of the industry. The Bureau of Labor Statistics reports that oil and natural gas extraction industries employed approximately 185,500 workers in December 2011, of which about 105,700 were classified as production workers.

The period since 2004, while difficult for American manufacturing as a whole, has been generally one of high profits for the oil industry. The generally high, although volatile, prices for oil prevailing since 2004 that have generated the high profits for the industry are seen as the critical factor in oil investment. Oil exploration tends to increase when prices are expected to increase, and possibly remain high, and investment decreases when prices are expected to decrease and possibly remain low for a sustained period. The variability and level of expected oil and natural gas prices are likely to be a more important factor in determining capital investment budgets, and hence exploration and production development budgets, than the repeal of a tax benefit that is capped by a relatively low wage bill for the companies.

Increase Geological and Geophysical Amortization Period

Geological and geophysical expenses are incurred during the process of oil and natural gas resource development. The most favorable tax treatment of these costs would be to allow them to be deducted in the year they are incurred. Requiring these costs to be amortized, or spread out for tax purposes, over several years is less favorable. The longer the amortization period, the less favorable the tax treatment, because a smaller amount is deducted each year, and more time is required to recover the entire cost.

Currently, the major integrated oil companies amortize geological and geophysical costs over a period of seven years. Independent producers amortize these costs over a period of two years. Under the FY2014 budget proposal, independent producers would have their amortization period extended to seven years, equalizing treatment with the integrated oil companies. The extended amortization period for independent producers is projected by the Administration to yield $1.3 billion over the period FY2014 to FY2023. IPAA estimated in 2010 that a similar proposal in the FY2011 budget proposal would likely reduce exploration and development activities on a dollar-for-dollar basis as a result of altering this tax provision. The API points out that exploration expenses tend to be higher in the United States than overseas, and the current law's favorable tax treatment of geological and geophysical expenses encourages the development of domestic resources. However, it seems unlikely that oil producers would reduce exploration investment to this extent if the spread of the market price over the full cost of oil exploration and development remains high, as it generally has been in the period of high oil prices since 2004. Additionally, if prices decline to a level near the cost of exploration and development, investment is likely to be curtailed even with the more favorable tax treatment of geological and geophysical expenses currently in place. If the industry were experiencing a time of stagnant oil prices that were near the cost of production, relatively small changes in tax expenditures might affect investment and production activities. However, in a time of high and volatile oil prices, small changes in tax expenses are likely to be overshadowed by price changes derived from other factors.

Other Tax Policies

The FY2014 budget proposal identifies a number of other proposed tax changes that would likely affect the oil industry. These changes include the repeal of the last-in-first-out (LIFO) accounting method, increasing the Oil Spill Liability Trust Fund taxes, reinstating Superfund taxes, and modifying the Dual Capacity Rule.

Last In, First Out (LIFO)

LIFO, as described by the API, is not a tax loophole, but a well-established accounting methodology to determine taxable earnings. Under LIFO accounting procedures, firms assume that the last unit of a good that the company acquires in its inventory is the first unit of the good that is sold. In periods of price inflation, or periods when the expected cost of acquiring inventories is rising, LIFO is beneficial in reducing taxes by allowing the cost deduction of the most recent (expensive) goods, independently of which goods were actually sold out of inventory.

The general upward movement of oil prices since 2004 has been, with the significant exception of the period when the effects of the recession drove oil prices down (September 2008 to January 2009), a favorable period for the oil industry to be using LIFO. To the extent that demand conditions and political unrest in oil exporting regions might keep the price of oil rising, keeping LIFO in place could be a tax advantage for the oil industry. API suggests that, if it were repealed, companies might have to redirect cash or sell assets to cover the tax payment, destroying some businesses. Using FY2014 Budget Proposal estimates, changing the LIFO provision for all industries could raise $80.8 billion over the period FY2014 to FY2023, with the API estimating that $28.3 billion of the total over the period would come from the oil and natural gas industries.

Oil Spill Liability Trust Fund

The FY2014 budget proposal includes a proposed increase in the Oil Spill Liability Trust Fund financing, by raising the tax on imported and domestic crude oil to 9 cents per barrel in 2014 and to 10 cents per barrel in 2017. The current tax is 8 cents per barrel, and under current law is set to rise to 9 cents per barrel in 2016. These proposed tax increases to finance the fund at a higher rate were possibly motivated as a response to the Deepwater Horizon oil spill in the Gulf of Mexico. These changes are expected to generate $64 million in 2014 and $1 billion over the period 2014 to 2023.

Superfund

The Superfund finances cleanup of the nation's high risk contaminated sites for which the responsible parties cannot be found, or cannot pay. Superfund taxing authority expired at the end of 1995. The FY2014 budget proposal would reinstate an excise tax of 9.7 cents per barrel on domestic and imported petroleum products, including crude oil sourced from bituminous deposits and kerogen-rich rock. In addition to the oil excise tax, other dedicated taxes on chemicals and corporate income have been proposed. The Administration and supporters of reauthorization believe that reinstatement of Superfund taxes would reduce the reliance on general Treasury revenues. The API contends that the excise taxes would impose a disproportionate share of the total cleanup costs on oil production and the sale of petroleum products. The API also questions whether a shift away from the use of general Treasury revenues as a source of funding would speed up cleanup efforts, if the overall appropriations from the trust fund were to remain constant and only the funding sources changed. According to the budget proposal, reinstating the Superfund Taxes would raise approximately $1.3 billion in 2014 and $20.2 billion from FY2014 to FY2023.

Dual Capacity Rule and Foreign Tax Credits

The credit for foreign income taxes paid, upon which the Dual Capacity Rule is based, dates back to 1918. Since that time corporations have been able to credit, directly from their U.S. income tax liabilities, income tax payments made to foreign governments. The period from the end of World War II to 1950 saw a new interpretation of this tax rule develop with respect to the oil industry. Before that time, oil-producing countries like Saudi Arabia charged the oil companies operating in their countries royalties, based on the resources extracted, as well as other taxes. For U.S. tax purposes, the royalties were treated as costs of doing business, hence, an expense, but not a direct credit against U.S. tax liabilities. In 1950, Saudi Arabia and the U.S. major oil companies operating there began negotiations to transform royalty payments into income taxes. This change had the effect of allowing the companies to pay more to Saudi Arabia, and increasing their after-tax earnings, at the expense of essentially transferring funds from the U.S. Treasury to the Saudi government.

Proposed modification of the dual capacity rules would restrict companies from claiming the full amount of foreign income taxes as a credit against U.S. taxes. Instead, the oil companies would only be allowed to credit amounts equal to the general corporate tax rate applicable to other industries. Any additional tax payments would be classified as tax-deductible operating expenses. The effect of the change in dual capacity rules would be to reduce after-tax revenues for the companies, as well as returns from overseas investments. This could lead to U.S. firms choosing to invest in fewer marginal overseas projects.

Modified rules for dual capacity taxpayers are estimated to generate $552 million in revenue in 2014 and $11 billion over the period 2014 through 2023.

Department of the Interior Budget

The Department of the Interior (DOI) budget proposal contains several changes in fees and other revenue-generating items that would affect the oil and natural gas industries.

The FY2014 budget proposal includes provisions to initiate royalty reforms, encourage the development of oil and gas leases, and improve revenue collection processes. In total, these proposals are expected to yield revenues of $2.5 billion over the period 2014 through 2023.

Although these fees and charges would increase the cost of exploring, developing, and operating oil and natural gas facilities under DOI's management, and are likely to reduce those activities as suggested by opponents of the proposals, the effects are likely to be small, as these fees represent only a fraction of the revenues, profits, or other taxes and fees paid to the government. Supporters of these fees might make the argument that they represent "user charges" consistent with environmentally sound management of resources on federal lands.

Conclusion

On the one hand, the tax changes proposed in Table 1 would increase tax collections from the oil and natural gas industries and may have the effect of decreasing exploration, development, and production, while increasing consumer prices and possibly increasing the nation's dependence on foreign oil. These same proposals, from an alternate point of view, might be considered to be the elimination of tax preferences that have favored the oil and natural gas industries over other energy sources and made oil and natural gas products artificially inexpensive, with consumer cost held below the true cost of consumption when external costs associated with environmental costs and energy dependence, among others, are included.

The quantitative effects of these proposals are likely to be small if oil prices remain high. The net revenue of the top 150 U.S. oil companies in 2012 was $91.1 billion, while total revenue was $1.02 trillion. The 2014 estimated tax revenues from the oil and natural gas industry tax proposals are approximately $3.8 billion, about 4% of net revenues, and one third of one percent of total revenues.