Federal Financial Interventions and Subsidies in Energy Markets 1999: Primary Energy

Report Contents
Report#:SR/OIAF/1999-03

Article 29: The Alternative Fuel Production Credit

The Alternative Fuel Production Credit (Section 29 of the Internal Revenue Code) was established by the Windfall Profit Tax of 1980 and became operational in the same year. Section 29 was designed to encourage the production of domestic energy from certain nonconventional sources and to reduce the Nation's dependence on energy imports. The credit applies to qualified fuels from wells drilled or facilities placed in service between January 1, 1980, and December 31, 1992. Production from qualifying wells can receive the credit on volumes produced through December 31, 2002; thus, the Section 29 credit affects the industry for 10 years after the qualifying deadline. The qualified fuels are:

Oil produced from shale and tar sands

Gas from geopressurized brine, Devonian shale, coal seams, tight formations, and biomass

Liquid, gaseous, or solid synthetic fuels produced from coal

Fuel from qualified processed formations or biomass

Steam from agricultural products.

The principal changes that have occurred since 1980 have been to extend the time limits by which wells or facilities must be placed in service and fuels sold in order to be eligible for the credit. The initial time limit for qualification was December 31, 1989, but the deadline has been extended twice by subsequent legislation. In 1989, legislation allowed a 1-year extension of the time limits. The Omnibus Budget Reconciliation Act of 1990 provided an additional 2-year extension. The 1990 act also eased the qualifying requirements for gas produced from tight sands after 1990.^a,b

The tax credit for nonconventional fuels is $3 per barrel of oil equivalent produced. (All prices as well as the credit are specified in 1979 dollars, but for actual use they are indexed for inflation relative to that base. Conversion factors are used to convert the various fuels into their crude oil equivalent for purposes of calculating the credit.) The credit is fully effective when the price of crude oil is $23.50 per barrel or less and phases out gradually as the price rises to $29.50 per barrel.^c The credit is reduced if certain other energy subsidies, such as government grants and tax-exempt financing, are used.

The tax credit appears to have had a substantial impact on the production of alternative fuels. Initially, it stimulated the development of nonconventional gas wells, but the early rates of growth were not sustained through the mid-1990s, as the 1992 deadline slipped further into the past. According to one study, in 1992, just before the deadline when newly drilled wells would no longer be eligible for the tax credit, 78 percent of gas wells completed were drilled for the exploitation of gas in coal seams, tight sands, and shale oil.^d The following year, their share had fallen to 61 percent. Although tight gas formations volumetrically account for the greatest share of U.S. nonconventional energy production, coalbed methane production has been affected most by the credit in recent years.^e Coalbed methane recovery totaled only 91 billion cubic feet in 1989 out of total U.S. gas production of 17 trillion cubic feet. By 1994 it had risen to 1.0 trillion cubic feet, or 5 percent of U.S. production. Since then, growth in coalbed methane recovery has been less dramatic. Its share of the market reached 6 percent in 1997, which is the latest year for which production data are available. The majority of production takes place in Colorado, New Mexico, and the Black Warrior Basin of Alabama.

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^aSection 29 was retained when the Windfall Profits Act was repealed in the late 1980s.
^bOther changes under the 1990 Act included extending the credit as it applies to production from biomass and liquid, gaseous, or solid synthetic fuels produced from coal. The extension is allowed for facilities placed in service before 1997 and in production through 2007. These fuels are relatively minor recipients of the alternative fuel production credit. The credit no longer applies to fuel from qualified processed formations or biomass or steam from agricultural products.
^cThe actual conversion formula is: $3 - (($3 * (reference price - $23.50) / $6). For reference, the $3 credit and range of $23.50 to $29.50 in 1979 dollars are the equivalent in 1999 dollars of a $6.20 credit based on a range from $48.55 to $60.95. The GDP deflator was used to convert 1979 dollars to 1999 dollars.
^dV.A. Kuuskraa and S.H. Stevens, "How Unconventional Gas Prospers Without Tax Incentives, Oil and Gas Journal (December 11, 1995).
^eProduction data for tight formation gas are difficult to compile, because it is often difficult to distinguish between tight formation gas and conventional gas being produced from the same field.

Unreported Tax Expenditures

The reporting of tax expenditures was mandated by the Congressional Budget Act of 1974 (Public Law 93-344). The Budget of the U.S. Government defines tax expenditures as "revenue losses due to preferential provisions of the Federal tax laws, such as special exclusions, exemptions, deductions, credits, deferrals, or tax rates." Although the concept of what constitutes a tax expenditure is clear, the determination of what exactly is a preferential provision is subject to interpretation. In preparing this section on energy-related tax expenditures, the Energy Information Administration relied entirely on the definitions of tax expenditures presented in Office of Management and Budget (OMB) documents.

Expenditures below the U.S. Treasury de minimis amount ($5 million) are not reported in standard OMB budget documents and therefore are not included in this report. A case in point is the tax expenditure resulting from deepwater royalty relief in the outer continental shelf. To date, these expenditures have fallen well below the $5 million cutoff. The Outer Continental Deep Water Royalty Relief Act was signed into law on November 28, 1995.^a The Act provides incentives for oil and gas production in the deep waters of the Gulf of Mexico by eliminating certain royalties on deepwater leases. "Specifically, it mandates volumes of royalty-free production from fields in water depths exceeding 200 meters, both for new leases . . . and for existing leases."^b The program is administered by the U.S. Department of Interior's Minerals Management Service. As of August 1999, four requests had been granted for deepwater tax relief.^c To date, the value of royalty reductions has been relatively small: $1.5 million in 1998 and $1.1 million in 1999 through April.^d

This report does not address quantitatively recently passed energy legislation whose budgetary impact has not yet been assessed by the OMB for the current fiscal year (1999) or for future years. A case in point is the Emergency Oil and Gas Guaranteed Loan Program Act (Public Law 106-51), signed into law on August 17, 1999, which provides $500 million in loan guarantees to independent producers who have experienced layoffs, production losses, or financial losses since January 1, 1997.

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^aThe Outer Continental Deep Water Royalty Relief Act was included as an amendment to the Alaska Power Administration Sale Act legislation (S. 395).
^bU.S. Department of Interior, Minerals Management Service, web site www.gomr.mms.gov/homep/whatsnew/newsreal/ 980115.html.
^cU.S. Department of Interior, Minerals Management Service, Gulf of Mexico Offshore Region Office.
^dU.S. Department of Interior, Minerals Management Service, Gulf of Mexico Offshore Region Office.

Nuclear Safety Research

In addition to DOE's nuclear R&D program, the U.S. Nuclear Regulatory Commission (NRC) will also spend $53 million (about 11 percent of its budget) on nuclear safety R&D in fiscal year 1999. NRC responsibilities include regulation of commercial nuclear power reactors; non-power research, test, and training reactors; fuel cycle facilities; medical, academic, and industrial uses of nuclear materials; and the transport, storage and disposal of nuclear materials and waste. The NRC's operations (including R&D) are fully funded by a fee levied on the operation of nuclear power plants. Hence, NRC safety research cannot be considered as a subsidy to the nuclear power industry.

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