Extension and Modification of Section 29 for Producing Fuel from Nonconventional Sources

Section 1345 of the CEB would extend and modify Section 29 of the Internal Revenue Code, established under the Windfall Profit Tax of 1980, under which tax credits were provided for producing fuel from nonconventional sources. Fuels that were eligible to receive the credit included: 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; and steam from agricultural products. For facilities producing gas from biomass or synthetic fuel from coal, the credit is available for production through 2007 from facilities placed in service before July 1, 1998. For all other sources to which Section 29 applied, the credit was available for production through 2002 for those facilities placed in service from 1980 to 1992.

In general, Section 1345 allows a credit of $3 (indexed for inflation with 2002 as the base year) per barrel (or Btu equivalent) for production from nonconventional sources for 4 years of production prior to 2010 for new wells placed in service through 2006. Fuels eligible to receive the new credit include: oil produced from shale and tar sands; gas from geopressurized brine, Devonian shale, coal seams, and tight formations; landfill gas; fuels from agricultural and animal waste; refined coal; coal-mine gas; and coke and coke gas. Production from existing oil and gas wells drilled from 1980 through 1992, previously eligible through 2002, is also eligible for the credit through 2006. For smaller landfills there is a credit of $3 for facilities placed in service after June 30, 1998, and before January 1, 2007, while the credit is reduced to $2 for larger landfills already required to add gas collection facilities. Refined coal facilities placed in service before January 1, 2008, are also eligible for 5 years of tax credit. The credit in Section 1345 is limited to an average daily production of 200,000 cubic feet of gas (or oil equivalent) per well or facility. The credit is fully effective when the price of crude oil is $35 per barrel or less and phases out gradually as the price rises to $41 per barrel.

Nonconventional Gas

For gas from tight formations (tight sands), Devonian shale (gas shales), and gas from coal seams (coalbed methane), EIA allowed a credit of 53 cents per thousand cubic feet ($3 per barrel Btu equivalent) for 4 years of gas production prior to 2010 for new wells placed in service through 2006. The credit was represented as an increment to the wellhead price in the first 4 years of a projected price path utilized to determine the decision whether or not to drill a well.

The primary benefit of Section 1345 lies in the increased development of nonconventional natural gas deposits (tight sands, gas shales, and coalbed methane) as a source of U.S. natural gas supply. In the Section 29 Case, the increased profitability of nonconventional fuels under Section 1345 is projected to result in significant drilling increases, higher reserve levels, and, ultimately, increased production (Table 4). During the period for which wells are eligible for the credit from 2004 to 2006, 20 percent more nonconventional gas wells are projected to be drilled in the Section 29 Case than in the Reference Case. Total nonconventional reserve additions over this period are projected to be 13 percent higher in the Section 29 Case than in the Reference Case. With the higher reserve base, cumulative nonconventional production is projected to be about 3 percent greater in the Section 29 Case from 2004 to 2009, the period during which the credit could be claimed (for 4 consecutive years) on production from an eligible well. Also of significance, the increased profitability of nonconventional gas activities (due to the tax credit) allows this production to come forth at a price that averages 8 cents lower during the period. With these lower prices, though, total Lower 48 production does not increase by the same amount (in absolute terms) as nonconventional production, since some of the more marginal conventional activities are no longer profitable. Section 1345 is projected to have a negligible effect upon net petroleum imports.

The cost of Section 1345 is the tax revenue not received by the Federal government as a result of the provision. EIA was not able to estimate tax revenue losses because NEMS does not track the production of wells drilled in a given year (a process called vintaging). Using the JCT’s estimates of the lost tax revenue from Section 1345, the projections of lost revenue are compared to projections of incremental natural gas production under the provision for the major nonconventional fuels (tight sands, gas shales, and coalbed methane) in Table 5.

The effects of Section 1345 on production from other fuels qualifying under the provision were not quantitatively analyzed within NEMS. In most instances, it was determined that the provision would have little or no effect or that any significant effect it might have could not be quantitatively analyzed. These fuels include gas production from previously eligible oil and gas wells (drilled prior to January 1, 1993), oil produced from shale and tar sands, gas from geopressurized brine, landfill gas, fuels from agricultural and animal wastes, refined coal, coal mine gas, and petroleum coke and coke gas.

Petroleum Coke and Coke Gas

In 2002, EIA data indicated that there were 56 U.S. refineries producing coke, all were built in the timeframes specified in Section 1345.⁵ The amount of tax credit allowed for coke producers (at $3 per barrel oil equivalent and subject to the daily limit) would be $2,172,000 per year (2002 dollars) for 2004 through 2009.⁶

There are currently three coke gasification facilities in operation, with two more planned in a few years.⁷ The three existing coke gasification facilities could jointly claim $116,000 per year for 2004 through 2009.⁸ Assuming the two planned facilities are to be placed in service by January 1, 2007, these two facilities could jointly claim an additional $78,000 per year for 2007 through 2009.

Given the short-term nature of the tax credit (2004 through 2006 for refinery capacity changes) and the size of the tax credit, the projections for coke and coke gas production under the CEB assumptions remained unchanged compared to the Reference Case. Consequently, the impact of this provision on oil or gas supply or oil imports is negligible.

Landfill Gas

Both large landfills subject to the landfill rule and small landfills that add collection facilities between June 30, 1998, and January 1, 2007, are eligible for a Section 29 tax credit. The credit only applies to new facilities, not existing facilities. The small landfills get $3 per barrel oil equivalent (in 2002 dollars) while the large landfills get a reduced credit, $2 per barrel oil equivalent, for the first 4 years of their operation. The last year of credits is 2009, so a facility brought on in the middle or latter part of 2006 would not get the full four years. The credit is also limited to only 200,000 cubic feet per day of production. Since a barrel of oil contains about 5.8 million Btu, these credits are worth approximately $0.52 (2002 dollars) per million Btu of gas for the small landfills and $0.34 (2002 dollars) per million Btu of gas for large landfills.

However, these same landfills are also eligible under Section 45 to receive the production tax credit for electricity generation from renewable fuels. Under this section, landfills brought on after the passage of the bill and prior to the January 1, 2007, are eligible. The credit is worth 1.2 cents per kilowatthour (two-thirds of the 1.8 cents available to some other renewables) for the first 5 years of the facility’s operation (half the period available for some other renewable facilities). To put this credit on a comparable basis with the Section 29 credit, a heatrate of 10,000 Btus per kilowatthour is assumed. With this assumption, the Section 45 credit translates to $1.20 per million Btu of gas. Also, Section 45 provides 5 years rather than the 4 years of the Section 29 credit. Since Section 45 is more economically attractive, runs for a longer period, and the quantity is not limited, landfill operators are expected to take advantage of it rather than Section 29. The tax credits to landfills are not expected to have a significant impact on natural gas supplies or oil imports.

Coal-Mine Gas

Coal-mine methane is methane trapped in coal beds which is currently uneconomic to produce, flared for reasons of safety prior to opening new mines, and not included in the recoverable resources in NEMS. Under Section 29 provisions, new coal-mine methane produced by drilling shallow wells between 2004 and 2006 would qualify for a tax credit equivalent to $0.52 per thousand cubic feet for a maximum of 4 years, ending in 2009. Economically recoverable coalbed methane is currently accounted for in NEMS and is produced when economic.

Based on marginal abatement costs for coal-related methane emissions provided by the Environmental Protection Agency (EPA) and used in a recent EIA study,⁹ at most 0.1 trillion cubic feet might be economic to produce annually for a maximum of 4 years under Section 29 incentives. However, such an increase is unlikely. The tax credit would only be available for a maximum of 4 years, and methane from coal mines has a slow production rate compared to conventional onshore natural gas wells. New infrastructure would have to be constructed in many cases, rendering some projects uneconomic, and the areas where coal mining expansion is planned may not coincide with the more economic of the coal-mine resources. In this case, the incremental natural gas production from coal-mine methane is expected to be very small.¹⁰

Refined Coal

The current Section 29 tax credit is available for coal-based synthetic fuels produced through December 31, 2007, provided the qualified facility was placed in service by June 30, 1998. To qualify for the Section 29 tax credit, the coal-based synthetic fuel must undergo a significant chemical change, which is generally defined as a measurable and reproducible change in the chemical bonding of the starting components. While there are multiple technologies that have been developed for producing coal-based synthetic fuel, most technologies comply with the required chemical change by applying a liquid binding agent such as diesel fuel emulsions, pine tars, or latex to the blend of coal feedstock, which is then mixed and further processed through industrial equipment. In most cases, the production of coal-based synthetic fuel uses a combination of one or more coal feedstocks, which may include run-of-mine coal, coal fines, low-grade coal and/or other types of “waste” coal.

In 2003, the U.S. Internal Revenue Service (IRS) conducted a review of the processes being used to produce solid synthetic fuels derived from coal, issuing an announcement of their findings on November 13, 2003. The IRS decision reflects the general belief that, although the processes do not produce the required level of chemical change, it would be unfair to change the rules regarding the production of solid synthetic fuels in the middle of the game. IRS Rev. Proc. 2001-34 specifies modifications to the allowable particle size of the coal feedstock and modifies the guidelines related to the processing procedures used to obtain a significant chemical change.

In 2002, EIA data indicated that there were 44 coal synfuel plants operating in the United States reporting receipts of 83.1 million short tons of coal. This represented 7.6 percent of U.S. coal production for the year. Of these 44 plants, 36 were located in Appalachia, 7 in the Eastern Interior supply region, and 1 in the West. Since the tax credits are based on the energy content of the finished product, measured in Btus, Section 29 qualified coal synfuels using Appalachian coals as a feedstock are worth considerably more than synfuels using lower-Btu western lignite and sub-bituminous coals as a feedstock. The current Section 29 provides for a production tax credit of approximately $3.00 per barrel of oil equivalent in 1979 dollars, which after adjustment for inflation, equals $6.35 per barrel of oil equivalent in 2002 dollars. Assuming that there are 5.8 million Btu per barrel of oil,¹¹ the tax credit for a qualifying solid synthetic fuel derived from a bituminous coal feedstock from Appalachia had a value of approximately $25 per short ton in 2002. Using this value, the total coal synfuel credit in 2002 for the 83.1 million tons reported to EIA is approximately $2 billion.

The tax credit provisions set forth in Section 1345 extend the tax credit for coal and waste coal to new faculties coming on-line after the enactment of the legislation and prior to January 1, 2008. Qualified new facilities will be eligible to receive a Section 29 tax credit for the first 5 years of operation. Relative to the current Section 29 guidelines, the new guidelines for qualifying coal synfuel facilities are substantially more restrictive. Covered facilities under the newly proposed guidelines require: 1) a 20-percent reduction in the emissions of nitrogen oxides and either sulfur dioxide or mercury compared to the emissions released when burning the original feedstock coal or comparable coal; 2) the refined coal product must be at least 50 percent higher in economic value than the feedstock; and 3) the facility cannot be any advanced clean coal technology unit.¹² In addition, the new guidelines reset the production tax credit to $3.00 per barrel of oil equivalent in 2002 dollars, with annual adjustments for inflation to commence in 2003. This last change reduces the value of the credit by more than half from its 2002 level.

Coal-to-liquids (CTL) conversion is not generally competitive with petroleum-based fuels unless the world oil price is greater than $30 per barrel. If world oil prices fail to reach that level, the effects of Section 1345 with a relatively small daily limit allowed for the tax credit¹³ would be insignificant to help overcome the economic barrier for the commercialization of CTL.

EIA is not able to provide a specific estimate of the impacts of the extended tax credits for coal synfuels derived from coal or waste coal. However, with a reduction in the credit value of more than 50 percent and a tightening of the qualification requirements, use of the credit is expected to be substantially below the $2 billion estimated for 2002.

Tables

Notes and Sources