The Obama Administration, in the FY2012 budget proposal, seeks to eliminate certain tax expenditures that benefit the oil and natural gas industries. Supporters of these tax provisions see them as comparable to those affecting other industries and supporting the production of domestic oil and natural gas resources. Opponents of the provisions see these tax provisions as subsidies for a profitable industry the government can ill afford, and impediments to the development of clean energy alternatives.
The FY2012 budget proposal outlines a set of proposals, framed in terms of deficit reduction, or termination of tax preferences, that would potentially increase the taxes on the oil and natural gas industries, especially those of the independent producers. These proposals include repeal of the enhanced oil recovery and marginal well tax credits, repeal of the current expensing of intangible drilling costs, repeal of the deduction for tertiary injectants, repeal of the passive loss exception for working interests in oil and natural gas properties, elimination of the manufacturing tax deduction for oil and natural gas companies, increasing the amortization period for certain exploration expenses, and repeal of the percentage depletion allowance for independent oil and natural gas producers. In addition, a variety of increased inspection fees and other charges that generate more revenue for the Department of the Interior are included in the budget proposal.
The Administration estimates that the tax changes outlined in the budget proposal would provide $22.8 billion in revenues over the period 2012 to 2016, and over $43.6 billion from 2012 to 2021. These changes, if enacted by Congress, also would reduce the tax advantage enjoyed by independent oil and natural gas companies over the major oil companies. On what would likely be a small scale, the proposals also would make oil and natural gas more expensive for U.S. consumers and likely increase foreign dependence.
This report will be updated as events warrant.
The Obama Administration, in the FY2012 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 and FY2011 budget requests. New revenue estimates for the 2012 proposed tax changes are $43.6 billion over the next decade, contrasted with estimates of $31 billion and $36 billion in 2010 and 2011, respectively, for essentially the same proposed changes. Although these proposals have failed to be implemented by Congress in FY2010 and FY2011, the current atmosphere of high deficits and high earnings by the major oil companies, coupled with a price of gasoline over $3 per gallon, might reduce resistance to increasing taxes on the industry.
The Administration characterizes the deductions and credits slated for elimination as tax preferences, or oil and gas subsidies, that are costly to U.S. taxpayers and do little to either provide incentives for increased production or reduce prices to consumers.1 A contrasting description is provided by the American Petroleum Institute (API), which describes the tax provisions slated for elimination as "cost-recovery methods that are similar to cost-recovery methods for many other types of taxpayers."2
The Administration characterizes repealing these tax preferences as eliminating market distortions, and links them to providing resources for investments in clean, renewable, and more efficient energy resources.
The Administration's proposals to shift the nation away from oil and to try to control the federal deficit have led to eight proposed 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 2012, the five-year period, 2012-2016, and the 10-year period 2012-2021.
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.3 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 continued to receive the benefit.
Table 1. FY2012 Oil/Gas Industry Tax Proposal Revenue Estimates
(in millions of dollars)
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Proposed Change |
2012 |
2012-2016 |
2012-2021 |
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Repeal Enhanced Oil Recovery Credit |
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Repeal Credit for Oil and Gas from Marginal Wells |
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Repeal Expensing of Intangible Drilling Costs |
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Repeal Deduction for Tertiary Injectants |
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Repeal Passive Loss Exception for Working Interests in Oil Properties |
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Repeal Percentage Depletion for Oil and Natural Gas Wells |
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Repeal the Domestic Manufacturing Deduction for Oil and Natural Gas Companies |
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Increase Geological and Geophysical Amortization Periods |
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Totals |
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As shown in Table 1, the proposed tax changes would have the effect of raising almost $3.5 billion in 2012. Almost all (96%) of the revenues from the proposed tax preference repeal from 2012-2021 would come from only three of the proposals. The repeal of the expensing of intangible drilling expenses, the repeal of percentage depletion, and the repeal of the manufacturing tax deduction for the oil industry would increase the industry's estimated tax payments by $41.9 billion through 2021.
The enhanced oil recovery tax 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, that can enhance the 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 weak demand, and the credit could provide the margin that keeps the wells in production.
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 world energy market balances result in low prices. It is believed that up to 20% of U.S. oil production and 12% of natural gas production is sourced from wells of this category. The credit was enacted in 2004, but has not been necessary because market prices have been high enough since that time to justify production on economic grounds without 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 to be eliminated on economic efficiency grounds if a reduction in petroleum demand is experienced.
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 exploratory wells or the development of wells for production. Intangible drilling costs cover a wide range of activities and things, including ground clearing, draining, and surveying, to wages, repairs, supplies, drilling mud, chemicals, and cement necessary 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 available from drilling rigs, reducing the cost of exploration of prospective oil and natural gas fields.
In the current tax law, the full expensing of intangible drilling cost is available to independent oil producers. Since 1986 major integrated oil companies have had to capitalize 30% of intangible drilling expenses over a 60-month period, rather than expense these costs in the current year.
Administration estimates are that repeal of the expensing of intangible drilling costs provision will yield $8.883 billion by 2016. 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 a reduction in investment in U.S. oil development of about $3 billion in the future.5 The IPAA's estimated reduction in oil development 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 cost this year was estimated by the IPAA to result in an immediate one-third reduction in drilling budgets.6
Actual reductions in drilling budgets are likely to be determined by the price of oil. If the price of oil settles 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 current price of oil near $100 per barrel, supported by political unrest in the Middle East, the additional tax expense is likely to have a smaller effect in reducing oil development activity.7
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 price of oil, was low. During a period of high oil prices, the repeal is likely to have a smaller effect on production levels.
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, $117 million from 2012 to 2016. 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 in oil and gas projects against other active income earned, and is believed to act as an incentive to induce investors to finance oil and gas projects.
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 depreciation for the oil industry, in effect equating 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 non-productive through obsolescence or through wearing out. Depreciation allowances are applied against the investment in capital equipment and depletion allowances are applied to oil deposits as a way to recover the initial investment.
In its current form, the allowance is limited to domestic U.S. production, by independent producers, on the first one thousand 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. 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 is vested in the national oil company, as a proxy for the state. The result is a lower share of revenues for companies producing outside the United States. The Administration projects that repeal of the percentage depletion allowance would yield approximately $5 billion over the period 2012 to 2016, and over $11 billion through 2021.
A provision in the proposed budget that affects both independent and the majors' oil and natural gas tax liabilities is the repeal of the manufacturing tax deduction. As shown in Table 1, the Administration estimates that the repeal of this deduction for the oil and natural gas industries would contribute $7.7 billion in revenue for the period 2012 to 2016. The total revenue might increase to $18.2 billion by 2021, according to the budget proposal.
This provision was enacted in 2004 as part of the American Jobs Creation Act 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 1999(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 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.8 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 165,000 workers in 2009, of which fewer than 100,000 were classified as production workers.
The period since 2004, while difficult for American manufacturing as a whole, has been one of record profits for the oil industry. The generally high prices for oil prevailing since 2004 that have helped generate the record profits are seen as the critical factor in oil investment. Oil exploration tends to increase when prices are increasing, and expected to remain high, and decrease in times of falling prices that are likely to remain low. The variability, and level of, expected oil and natural gas prices is 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.
Geological and geophysical expenses are incurred during the process of oil and natural gas resource development. The most favorable tax treatment of these costs is 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 in 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. In the FY2012 budget proposal, independent producers that benefit from a shorter amortization period 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 $1.1 billion in revenue over the period 2012 to 2016. The Independent Petroleum Association of America estimated in 2010 that a similar proposal in the FY2011 budget would likely reduce exploration and development activities on a one-to-one dollar basis as a result of altering this tax provision. However, it seems unlikely that oil producers would reduce exploration investment to this extent if the spread of 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 more favorable tax treatment of geological and geophysical expenses. If the industry were experiencing a time of stagnant oil prices that were near the cost of production, relatively small changes in tax expenses might affect investment and production activities. However, in a time of high and volatile oil prices, small changes in tax expense are overshadowed by price variations.
The American Petroleum Institute (API), in responding to President Obama's FY2012 budget proposal, identifies a number of other proposed tax changes which would affect the oil industry. These changes include the repeal of the last-in-first-out (LIFO) accounting method, reinstating Superfund taxes, and modifying the Dual Capacity Rule.
LIFO, as described by the API is not a tax loophole, but a well-established accounting methodology to determine taxable earnings.9 LIFO accounting procedures assume that the last goods a company acquires are the first goods they sell. In periods of inflation, or periods when the expected cost of acquiring inventories is rising, LIFO is beneficial in reducing taxes by allowing the deduction as a cost 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, with the exception of the period when the recession drove oil prices down (September 2008 to January 2009), been a favorable period for the oil industry to be using LIFO. To the extent that political unrest in oil producing regions might keep the price of oil rising, keeping LIFO would be a tax advantage for the oil industry. API states that companies might have to redirect cash or sell assets to cover the tax payment, driving some firms to bankruptcy. API estimates that repealing LIFO will result in additional tax liabilities of $22.5 billion for the oil industry.10
Reinstating Superfund taxes was judged by API to unfairly impose higher taxes on oil production and the sale of petroleum products. API's position is that the oil industry does not account for substantial amounts of the Superfund liability, yet would result in additional tax liabilities for the industry of $11.2 billion. From an environmental point of view, the API points out that reinstating the taxes would not ensure that remediation or cleanup will happen more quickly.11
The budget proposal also proposes to increase the Oil Spill Liability Trust Fund by raising the tax on domestic and imported oil to 9 cents per barrel after 2011 and 10 cents per barrel after 2016. The current plan is to raise the tax to 8 cents per barrel after 2011 and 9 cents per barrel after 2016. These proposed increases are likely a response to the Deepwater Horizon oil spill in the Gulf of Mexico.12
The credit for foreign income tax, upon which the Dual Capacity Rule is based, dates back to 1918. Since that time corporations have been able to deduct from their U.S. income taxes 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 not a direct credit against U.S. taxes. In 1950, Saudi Arabia and the U.S.-owned oil companies began negotiations to transform royalty payments into income taxes which had the effect of allowing the companies to increase after tax earnings while, in effect, transferring funds from the U.S. Treasury to the Saudi government.13
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 they would only be allowed to credit amounts equal to the general corporate tax rate applicable to other industries. Additional taxes would be classified as an operating expense. The effect of the change in dual capacity rules would be to reduce after-tax revenues and returns from overseas investments. This could lead to U.S. firms choosing to invest in fewer marginal overseas projects.
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 FY2012 budget proposal includes provisions to transfer both the cost of both onshore and offshore drilling inspection fees to the companies, as well as the cost of oil and gas permit fees. Additionally, fees would be established for new non-producing oil and gas leases to encourage development and production. Royalty rate adjustment and terminating the royalty-in-kind program would also be ended.
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 a percent 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.
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 prices and increasing the nation's foreign oil dependence. 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 gas products artificially inexpensive, with consumer costs held below the true cost of consumption, when the external costs associated with environmental costs and energy dependence, among other effects, are included.
Whichever view is adopted, the real effects of these proposals on oil and natural gas production, consumption, and import are likely to be small relative to both the federal deficit and the revenues of the oil and natural gas industries.
| 1. |
FY2012 federal budget request, Terminations, Reductions, and Savings, Dept. of Energy, p. 52. |
| 2. |
Petroleum Intelligence Weekly, "Obama Targets Oil Industry Tax Breaks," Vol. L, No. 7, February 21, 2011, p. 3. |
| 3. |
Independent oil companies are generally defined to mean non-integrated companies. They might, for example, work in exploration and production, but not in refining and marketing. |
| 4. |
Tax credits are direct offsets to the company's tax liability and are generally considered to be preferred to deductions. |
| 5. |
Independent Petroleum Association of America, "New Natural Gas and Oil Taxes Would Crush America's Clean Energy and Energy Security," available at http://www.ipaa.org/news/docs/ObamasNewtaxes2009.pdf. |
| 6. |
Independent Petroleum Association of America, "Increasing Taxes on America's Independent Natural Gas and Oil Producers—A Bad Idea," available at http://www.ipaa.org. |
| 7. |
On February 22, 2011 the observed price of West Texas Intermediate on the NYMEX was $94.55 per barrel. |
| 8. |
The refinery can attain different utilization rates with only minor variations in labor utilization. |
| 9. |
American Petroleum Institute, "Significant Industry Tax Issues Contained in President Obama's FY 2012 Budget," February 2011, available at http://www.api.org. |
| 10. |
Ibid. |
| 11. |
For more detail on the Superfund, see CRS Report R41039, Comprehensive Environmental Response, Compensation, and Liability Act: A Summary of Superfund Cleanup Authorities and Related Provisions of the Act, by [author name scrubbed]. |
| 12. |
See National Pollution Trust Fund Center, U.S. Coast Guard, for details on the Oil Spill Liability Trust Fund. |
| 13. |
Daniel Yergin, The Prize, Simon & Shuster, New York, 1991, p. 446. |