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1 1 (November 23, 2016)

handle is hein.crs/govcewu0001 and id is 1 raw text is: FF. ' riE S-' $. h ,i , mppm qq\ p\w -- , gmmw' go I MM 11LULANJILiM, 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. Ta rr,-efrences 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 .O 'T

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