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 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. 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. 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. 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. 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 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. 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.