Oil and Natural Gas Industry Tax Preferences

November 23, 2016 Oil and Natural Gas Industry Tax Preferences Corporate income tax policy was an issue in the 2016 presidential campaign and is also expected to be taken up by the 115th Congress. Debate has centered both on the tax rate as well as the tax base. The issue with respect to the tax rate is whether the current top federal corporate rate of 35% is too high compared to that levied by other countries, reducing the competitiveness of U.S. firms. However, some say that the average effective federal corporate income tax rate may be as low as19%-20% due to a variety of specialized tax deductions and credits, known as tax preferences. These tax preferences tend to reduce the tax base for the firms that meet the qualifications to use them, reducing their tax payments and yielding a lower effective tax rate. Not all industries have access to the same set of tax preferences, and, as a result, companies in different industries, with the same net taxable income, might be liable for different tax payments. The result is unequal treatment under the tax law which can amount to a subsidy for some firms in some industries. The oil and natural gas industries have access to a variety of favorable tax preferences which might reduce the industry’s overall tax burden. These tax preferences have been a target for repeal by the Obama Administration since 2009, but Congress has not acted on Administration proposals. In many cases, the tax preferences proposed for repeal are technical in nature, and have a long history in the oil industry. In addition, some tax preferences are not equally available to all firms in the industry. For example, in the oil industry, percentage depletion allowances can be taken by independent oil companies but not by the major oil companies. Tax Preferences The enhanced oil recovery credit provides for a tax 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 availability of the credit depends on official guidance establishing that oil prices are “low” during the previous calendar year as defined in statute. While the credit was not available due to high oil prices from tax years 2006 through 2015, low oil prices in 2015 allow the full 15% credit to be used by oil companies in tax year 2016. The credit for oil and natural gas from marginal wells 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. For oil wells, the credit of $3 per barrel applies to the first three barrels produced per day by a well, yielding a maximum tax credit of $9 per well, per day. For natural gas, the credit is set at $0.50 per thousand cubic feet of natural gas production, again with limits to the applicable volumes. However, in the case of the marginal wells credit, unlike that of the enhanced recovery credit, a determination was made that market prices were not low enough during 2015 to activate the credit. While both the enhanced oil recovery credit and the credit for oil and gas production from marginal wells might provide some incentive to produce more oil when prices are low, that result might have the effect of reducing the pressure for prices to rise, which would provide greater benefits for more oil producers. The expensing of intangible drilling costs has been part of the federal tax code since 1913. Current expensing from income in the year incurred is preferred by industry because it allows costs to be recouped more quickly. Intangible drilling costs include the cost of items that have no salvage value, but are necessary for the drilling of an exploratory well, or to develop a well for production. Intangible drilling expenses include a wide variety of activities and physical supplies, including ground clearing, draining, surveying, wages, repairs, supplies, drilling mud, chemicals, and cement required to begin drilling, or to prepare a well for development. Under current law, full current year expensing of intangible drilling costs is available only to independent oil producers. Since 1986, the integrated oil companies have been able to expense 70% of their intangible drilling cost and capitalize the remaining 30% over a 60-month period. Eliminating this provision could contribute to equalization of the tax treatment of independent and major oil companies, eliminating an incentive for smaller, independent oil firms to engage in oil and natural gas exploration. The tertiary injection deduction applies to well injections above and beyond natural well pressure, or secondary injection of water, and allows the expense associated with these activities to be fully deducted in the current tax year. The deduction includes costs associated with acquiring or producing the injectant, as well as the costs associated with injecting, re-injecting, and recovering the injected materials. Carbon dioxide may be one of the materials injected into wells. Oil firms must choose between using this deduction or the enhanced oil recovery credit to avoid duplicate expensing of the same costs. The passive loss exception for working interests in oil properties exempts investments in oil and natural gas exploration and development from being categorized as a “passive income” (or loss) with respect to the Tax Reform Act of 1986. The passive loss exception permits the deduction of losses accrued in oil and natural gas projects against other active income earned without limitation. The https://crsreports.congress.gov Oil and Natural Gas Industry Tax Preferences provision is designed to provide an incentive for oil and natural gas financial investment. Percentage depletion is the practice of deducting from an oil company’s gross income a percentage of value, in the current law 15%, which represents, for accounting and income 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 idea that both capital equipment and oil deposits are “wasting resources” in the sense that they both require capital investment to generate income, and they both will eventually become non-productive. Percentage depletion was eliminated for the major oil companies in 1975. 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 oil producer’s net income. The domestic manufacturing tax deduction 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. However, the rate available to the oil and natural gas industries was capped at 6%. The tax base is corporate net income from domestic manufacturing activities, capped by a limitation depending on the size of the company’s payroll. Questions have arisen concerning whether it is appropriate to classify the oil and natural gas industries in the manufacturing sector if the objective of the deduction is to increase domestic employment by lowering the company’s tax liability. Lower labor costs are less likely to result in higher output and lower product prices in the domestic oil market because of the convergence of domestic and international market prices for oil. The geological and geophysical amortization period for the major integrated oil companies is seven years. Independent producers amortize these costs over a period of two years. Equal treatment would have equal amortization periods for all firms. The most favorable treatment of these costs from the point of view of the oil industry would be to allow current expensing. The longer the amortization period, the longer is the period over which these costs might be recovered through a tax deduction. Whether a zero, two, or seven year period is chosen depends on the balancing of the incentive given to the oil industry to explore new oil fields, compared to the benefits of granting favorable treatment to smaller oil firms. Tax Rates, Tax Base, and Tax Revenues The Office of Management and Budget (OMB), in the Analytical Perspectives publication, part of the Fiscal Year 2017 federal budget, estimated the revenue implications of eliminating in 2016 the oil and natural gas industries tax preferences as described in this In Focus. OMB projects the increased revenues that might accrue in each year from 2017 through 2021 as well as a long term estimate over the period 2017 through 2026. Over the period 2017-2021, eliminating these tax preferences was estimated to yield about $19.2 billion. Over the period 2017-2026 almost $40 billion could be gained. The key tax preferences with respect to generating tax revenue are the enhanced oil recovery credit, the expensing of intangible drilling expenses, percentage depletion, and the domestic manufacturing deduction. Eliminating these four preferences account for approximately 94% of the estimated revenues gained over the 2017-2021 time period. Tax revenue is the product of multiplying the tax rate times the tax base. This suggests that the growth in tax revenue (either positive or negative) is the sum of the growth rates of the tax rate and the tax base. If, for example, the tax base is broadened by a certain percent, a specific percent cut in tax rates is possible with no expected change in revenues. A greater percentage cut in the tax rate is likely to reduce revenues and a smaller cut might increase revenues. However, interactive effects might change the simple relationship. If changes in the tax rate change the incentives of the taxpayer, a change in tax rates might affect the tax base, altering the simple relationship. Conclusion While the eight oil and natural gas industry tax preferences may be considered for repeal in the current environment of tax reform, their repeal is likely to be opposed by the segments of the industry that benefit from them. However, a reduction in the general tax rate is likely to be seen as a benefit for the industry in general. Robert Pirog, Specialist in Energy Economics IF10512 https://crsreports.congress.gov Oil and Natural Gas Industry Tax Preferences Disclaimer This document was prepared by the Congressional Research Service (CRS). CRS serves as nonpartisan shared staff to congressional committees and Members of Congress. It operates solely at the behest of and under the direction of Congress. Information in a CRS Report should not be relied upon for purposes other than public understanding of information that has been provided by CRS to Members of Congress in connection with CRS’s institutional role. CRS Reports, as a work of the United States Government, are not subject to copyright protection in the United States. Any CRS Report may be reproduced and distributed in its entirety without permission from CRS. However, as a CRS Report may include copyrighted images or material from a third party, you may need to obtain the permission of the copyright holder if you wish to copy or otherwise use copyrighted material. https://crsreports.congress.gov | IF10512 · VERSION 2 · NEW