In the late 1970s and early 1980s, environmental and energy security concerns were addressed at the Federal level by several key pieces of energy legislation. Among them, the Public Utility Regulatory Policies Act of 1978 (PURPA), P.L. 95-617, required regulated power utilities to purchase alternative electricity generation from qualified generating facilities, including small-scale renewable generators; and the Investment Tax Credit (ITC), P.L. 95-618, part of the Energy Tax Act of 1978, provided a 10-percent Federal tax credit on new investment in capital-intensive wind and solar generation technologies [98].

EPACT included a provision that addresses problems with the ITC—specifically, the lack of incentives for operation of wind facilities. EPACT introduced the renewable electricity PTC, a credit based on annual production of electricity from wind and some biomass resources. The initial tax credit of 1.5 cents per kilowatthour (1992 dollars) for the first 10 years of output from plants entering service by December 31, 1999, has been adjusted for inflation and is currently valued at 1.8 cents per kilowatthour (2003 dollars) [99, 100].

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The original PTC applied to generation from tax-paying owners of new wind plants and biomass power plants using fuel grown in a “closed-loop” arrangement (crops grown specifically for energy production, as opposed to byproducts of agriculture, forestry, urban landscaping, and other activities). In its early years, the PTC had little discernable effect on the wind and biomass industries it was designed to support (Figure 26). Although there have not been any commercial closed-loop generators, by 1999, when the provision was originally set to expire, U.S. wind capacity had begun growing again, and the PTC supported the development of more than 500 megawatts of new wind capacity in California, Iowa, Minnesota, and other States. Wind power development was also encouraged by State-level programs, such as the mandate in Minnesota for 425 megawatts of wind power by 2003 as part of a settlement with Northern States Power (now Xcel Energy) to extend on-site storage of nuclear waste at its nuclear facility [101].

In 1999, the PTC was allowed to expire as scheduled, but within a few months it was retroactively extended through the end of 2001 [102], and poultry litter was added to the list of eligible biomass fuels. Although wind power development slowed significantly in 2000, 2001 was a record year with as much as 1,700 megawatts installed [103]. Again, State and local programs, including a significant renewable energy mandate program in Texas, also supported new wind installations.

The PTC was allowed to expire again on December 31, 2001, while Congress worked on a comprehensive new energy policy bill. It was retroactively extended a second time to December 31, 2003, as part of an omnibus package of extended tax credits passed in response to the economic downturn and terrorist attacks of 2001 [104].

Like the 1999 expiration and extension, the extension of the PTC in 2002 was followed by a lull in wind power development; however, in 2003, the year leading up to the expiration, the wind industry saw significant growth of almost 1,700 megawatts [105], approaching the record set in 2001. Significantly, while many 2003 builds still relied on multiple incentives (for example, the PTC plus a State program) to achieve economic viability, some (in Oklahoma and other States) were developed with little government support beyond the PTC [106].

An extension of the PTC program to eligible plants entering service on or before December 31, 2005, was passed as part of the Working Families Tax Relief Act of 2004 (P.L. 108-311). In addition, the American Jobs Creation Act of 2004 (P.L. 108-357) expanded the credit to other renewable resources, such as open-loop biomass, geothermal, and solar electricity, as detailed below.

With reductions in capital costs and increases in capacity factors [107], wind power technology has improved since the introduction of the ITC and PTC. It is likely that the installations spurred by those incentives allowed the industry to “learn by doing” and thus contributed to improvement of the technology. There were, however, other factors that contributed to cost reductions during the period, including government-funded research and development and large markets for wind power technology that were created by subsidy programs in other countries, especially, Denmark and Germany.

The AEO2005 reference case, assuming no extension of the PTC beyond 2005 (as provided for in current law as of October 31, 2004), projects that the levelized cost of electricity generated by wind plants coming on line within the next few years would range from approximately 4.5 cents per kilowatthour at a site with excellent wind resources [108] to 6.0 cents per kilowatthour at less favorable sites. To incorporate the effect of the current 1.8-cent tax credit over the 10-year eligibility period for those wind plants, the projections account for both the tax implications and the time value of the subsidy. As a tax credit, the PTC represents 1.8 cents per kilowatthour of tax-free money to a project owner. If the owner did not receive the tax credit and wanted to recoup that 1.8 cents with taxable revenue from electricity sales, 2.8 cents would have to be added to the sales price of each kilowatthour, assuming a 38-percent marginal tax rate.

Applying the same assumptions used to derive the 4.8-cent total levelized cost of wind energy over a 20-year project life, the levelized value of the PTC to a wind project owner is approximately 2.1 cents per kilowatthour. Similarly, the lower value of the PTC for other resources could be expected to reduce the levelized cost of prime geothermal sites from 4.4 to 3.6 cents per kilowatthour, and to reduce the levelized cost of a new dedicated biomass plant burning low-cost eligible urban or agricultural waste from 5.1 to 4.5 cents per kilowatthour. Solar projects with high capital costs and relatively low capacity factors probably would benefit more from the available 10-percent investment tax credit than from the PTC (Table 22).

In the reference case, the projected levelized cost for electricity from new natural gas combined-cycle plants is 4.7 cents per kilowatthour, and for new coal-fired plants the projected cost in 2010 is 4.3 cents per kilowatthour [109]. The value of the incremental fuel and capacity displaced by wind power in 2010 is 4.3 cents per kilowatthour in the reference case. Thus, it is easy to see how the PTC could make wind plants an attractive investment in the mid-term electricity market.

In view of the history of past PTC extensions, another extension beyond the current 2005 expiration date seems well within the realm of possibility. Given the uncertainty regarding the long-term fate of the PTC, EIA examined one possible outcome for an extension of the PTC. The PTC extension case is not meant to represent any expectation about future policy decisions regarding the PTC, but rather to provide a useful indication of the impacts of the PTC program on future energy markets relative to the reference case forecast, which assumes no extension of the PTC beyond 2005. This case is based on an “as-is” extension to 2015 of the expanded renewable electricity PTC program, as expanded by the American Jobs Creation Act of 2004 to facilities placed in service by the end of 2015.

The current PTC law provides a tax credit of 1.8 cents per kilowatthour for the first 10 years of operation to new wind plants, dedicated biomass plants burning closed-loop fuel or poultry litter, and certain approved fossil fuel plants co-firing with closed-loop renewable fuels. A credit of 1.8 cents per kilowatthour is provided for the first 5 years of operation to new geothermal and solar plants [110], and a credit of 0.9 cent per kilowatthour is provided for the first 5 years of operation to new dedicated biomass plants burning a wide variety of “open-loop” fuels, such as urban wood wastes, landscaping wastes, agricultural residues, and forestry residues. Landfill gas and municipal solid waste mass-burn facilities are eligible for the “open-loop” credit as well, although this would preclude taking advantage of other tax credits offered to some of those facilities.

Each of the credits is modeled as specified in the law, with the exception of the “closed-loop” credits for dedicated biomass plants and approved co-firing applications, the tax credit for photovoltaics, and the credit for refined coal. Because of the long establishment times and relative expense of energy crops, it is assumed that there will be no dedicated, closed-loop biomass plants able to take advantage of an extension of the PTC to 2015. Furthermore, the eligibility of co-firing plants to take advantage of the credit is to be determined on a case-by-case basis by the Department of Energy, and determining which or how many plants will be able to qualify is beyond the scope of this analysis. This analysis assumes that no PTC is given for co-firing. Geothermal, utility-owned photovoltaics, and solar thermal power applications are all eligible for either the PTC or the ITC. In the case of photovoltaics, which has very high investment costs and relatively low annual output per unit capacity, the ITC is estimated to be the more valuable of the two tax credits, and it is assumed that it will be preferred over the PTC. EIA does not currently provide projections for refined coal markets.

The PTC extension case assumes an uninterrupted extension of the PTC through 2015. As indicated above, the PTC has historically been subject to a series of expirations with retroactive extension for short periods (typically, 2 years per extension). The resulting uncertainty for the relatively long-term cycle of electricity market investment may have a significant impact on the ability of the industry to exploit the subsidy. The observed “packing” of construction in the last 6 months or so of each new eligibility window may serve to increase investment cost. In addition, uncertainty about the future availability of the PTC may affect infrastructure investment decisions that could lead to fuller realization of cost-reduction opportunities [111].

In the PTC extension case, wind power has the largest projected gains, although landfill gas, geothermal, and dedicated, open-loop biomass resources all are projected to see some capacity expansion. Installed wind capacity in 2015 is almost 63 gigawatts in the PTC extension case, compared to 9.3 gigawatts in the reference case. This 580-percent increase in capacity results in a 650-percent increase in generation from the reference case projection for 2015 (206 billion kilowatthours in the PTC extension case compared to 27 billion kilowatthours in the reference case).

In 2015, geothermal capacity in the PTC extension case (3.23 gigawatts) is more than 20 percent greater than in the reference case (2.66 gigawatts), resulting in 30 percent more electricity generation from geothermal resources in 2015 (Table 23). With limited availability of new sites, new landfill gas capacity in 2015 is only 50 megawatts greater in the PTC extension case than the reference case projection of 3,630 megawatts. Although new dedicated biomass capacity in 2015 is almost 65 percent greater in the PTC extension case than in the reference case (3.39 gigawatts compared to 2.06 gigawatts), total biomass generation in the electric power sector in 2015 is only 10 percent higher than in the reference case (33.13 billion kilowatthours compared to 30.01 billion kilowatthours). This is largely a result of a significant decline in the use of biomass for co-firing applications, as the dedicated plants receiving the tax credit generally are expected to have a competitive advantage over co-firing plants in obtaining open-loop fuel.

Although geothermal capacity and dedicated biomass capacity in the PTC extension case continue to grow after the assumed 2015 expiration of the PTC, wind capacity expansion all but stops when the PTC expires. Because geothermal and biomass compete as baseload resources, their relative economics in the 2015 to 2025 time frame are similar in the reference and PTC extension cases; however, both benefit from reduced technology costs as a result of “learning-by-doing.” Wind, on the other hand, competes as an intermittent resource, with much of its generation displacing intermediate-load energy rather than peak or baseload energy. Initially, the displaced load consists of a significant amount of natural-gas-fired generation, with a relatively high fuel cost; however, after significant gas-fired generation is displaced, more coal-fired generation (with lower fuel costs) is displaced. In the PTC extension case, the avoided cost of wind generation is reduced by as much as 15 percent in 2020 from the reference case projection.

The total incremental cost to the U.S. Treasury of extending the PTC from 2005 to 2015 is estimated at $17 billion in lost tax revenue (all cumulative money calculations are in 2003 dollars, discounted at 7 percent per year unless otherwise noted). The electric power industry incurs $12 billion in cumulative additional costs through 2025 in the PTC extension case compared to the reference case; however, this additional expense is more than compensated for by the subsidy. Because the net effect of the PTC extension is a slight reduction in end-use electric power prices, electricity consumers save about $37 billion in end-use electricity expenditures through 2025 in the PTC extension case compared to reference case. In addition, the assumed PTC extension significantly reduces demand for natural gas in the electric power sector, lowering natural gas prices for all consumers. Total natural gas expenditures by consumers other than electric utilities are reduced by $13 billion through 2025 in the PTC extension case compared to the reference case. About $16 billion of the $17 billion in taxpayer cost is allocated to wind energy resources as a result of both the significantly higher level of PTC-induced wind generation and the higher PTC value and claim period for wind projects than for geothermal or open-loop biomass projects.

Notes and Sources

Contact: Chris Namovicz
Phone: 202-586-7120
E-mail: chris.namovicz@eia.doe.gov