over the next few years, but the technology is not expected to be commercially available until those units have gone through several years of testing. For the CCTI case, the 2005 commercial availability date was maintained, effectively limiting the facilities able to take advantage of the PTC to the expected demonstration units. Fuel inputs were also expanded to include currently available wood residues and waste in addition to dedicated energy crops, which are assumed not to be available until 2010. While it is plausible that the PTC could encourage the construction of some older, less efficient direct-fired blomass boiler units, that technology was not specifically modeled. It is believed that the relatively low efficiency of direct-fired units would make them economically unattractive. The model was also modified in the CCTI case to allow coal plants to use biomass for a portion of their fuel if it was economical. It was assumed that a coal plant could use biomass to displace up to 4 percent of the coal it would normally use. Current research has shown that a typical coal-fired boiler can fire from 3 to 5 percent blomass without a costly retrofit. Coal plants can consume larger shares of biomass, perhaps as much as 10 to 15 percent of their fuel. if new fuel handling systems are added and boiler firing equipment is modified. Such modifications are expensive. however ($250 or more per kilowatt of capacity), and the short length of the PTC for biomass co-firing makes it unlikely that plant operators would be willing to make such investments. An offline analysis was performed to match the availability of relatively low-cost biomass with the amount of coal capacity in a State. The maximum co-firing share allowed in any region was the minimum of the available low-cost biomass and the available coal capacity (assuming the use of 4 percent biomass) matched at the State level. Because there were States where the match was not good-large amounts of blomass but few coal plants, or many coal plants but little biomass--the maximum amount of coal that could be displaced by co-firing with biomass was determined to be 1.8 percent nationally. (For example, Oregon has a substantial amount of mill residues that could be used for co-firing in coal plants, but there is very little coal-fired capacity in the State.) Among the regions in the model, the share varied from 0 to 4 percent. In addition, because there are factors that may constrain the development of a biomass co-firing market that are not represented in the biomass supply curves used, several other modifications were made. The biomass supply curves do not include the costs and time associated with things such as ensuring that an adequate fuel supply is available near a specific plant, testing the fuel to see if plant modifications are needed, designing and making plant modifications, applying for any licenses that are needed, and, potentially, getting air permit changes approved. In addition, because many coal plant operators are in the midst of making changes to comply with new environmental regulations and preparing for a restructured electricity market, they are reluctant to entertain other changes at this time. To reflect the impact of these factors, the co-firing shares were phased in over time, and a hurdle rate was added to the cost of biomass fuels. In the reference case, the co-firing shares were phased in between 1999 and 2015, and a hurdle rate of 1 cent per kilowatthour was assumed. In other words, for biomass fuel to be considered, it had to lower the operating costs of the plant by 1 cent per kilowatthour. In the CCTI co-firing case, the shares were phased in between 1999 and 2005, and the hurdle rate was assumed to start at 1 cent before declining to 0.1 cent by 2005. Essentially it was assumed that the availability of the biomass co-firing PTC would lead to faster development of the biomass co-firing fuel market and a reduction in the costs incurred in preparing to use the fuel. Results Biomass As discussed in the methodology section, because new biomass gasification plants are not expected to be commercially available until 2005, the extension and broadening of the biomass PTC does not lead to more capacity being added solely on an economic basis (Table 20). However, the extension of the PTC may encourage additional demonstration efforts. In the reference case, 248 megawatts of testing and demonstration plants were assumed to come on line within the PTC period. In the CCTI case, an additional 30 megawatts of biomass gasification demonstration plants, bringing the total to 278 megawatts, are expected to be added from 1999 through 2004. The increase in biomass generation and reduction in carbon emissions because of the 30 additional megawatts added in the CCTI case are small. In 2010, the carbon savings amount to 0.4 million metric tons, less than 0.1 percent of total electricity carbon emissions. However, because the full 278 megawatts added are expected to take the tax credit, the tax consequences are larger. In 2010, if all the expected demonstration plants took advantage of the PTC, tax collections would be $23 million lower. Approximately 11 percent of the tax savings would go to the 30 megawatts induced by the program, and the remaining 89 percent would go to capacity expected to be built even without the program. Table 20. Projected Effects of the CCTI Biomass Energy Production Tax Credit, 2005, 2010, and 2020 Note: Excludes biomass co-firing at coal plants. The results presented here hinge on the commercial availability of biomass gasification technology and the development of the needed biomass fuel supply within the PTC time frame. The near-term focus of the PTC will make this a challenge. Uncertainties regarding the development of biomass technology include availability and proximity of the biomass fuel supply; the economics, which are highly site specific; the potential of green power programs; and potential sulfur emissions, which have been reported for a Minnesota biomass plant that burns alfalfa 59 The biomass co-firing provision of the CCTI has a more significant impact than the PTC for new plants; however, because the co-firing credit expires in 2004, the impact declines somewhat in the later years. In 2004, electricity generation from co-fired biomass is projected to be 18.6 billion kilowatthours in the CCTI case, about 3.4 times the reference case level (Table 21). As a result, total carbon emissions are 3 million metric tons lower in that year. The cost of the subsidy is estimated to be about $595 million in tax revenue reductions, with about 38 percent going to facilities that would have used biomass co-firing without the PTC. "Anecdotal information suggests that new units recently or about to come on line are using some specialized low-cost waste stream. Table 21. Projected Effects of the CCTI Biomass Energy Co-firing Tax Credit, 2004, 2005, 2010, and 2020 Source: Energy Information Administration, National Energy Modeling System runs CCTIBAS.D040799A and CCTICOF.D040799A. It is assumed in this analysis that the PTC would encourage power plant operators and biomass fuel suppliers to overcome the hurdles that are keeping them from taking advantage of the low-cost supplies that appear to be available. For example, electricity producers might maintain their relationships with biomass fuel suppliers once the PTC has induced such purchases. A recent example of such a change is the use of low-sulfur subbituminous coal in boilers originally designed only for bituminous coal, encouraged by the sulfur emission reduction requirements of the Clean Air Act Amendments of 1990 (CAAA90). Before the CAAA90 requirements were implemented, it was believed that the plants could not burn subbituminous coal. After testing and minimal modification, however, use of subbituminous coal in such boilers expanded significantly. For both biomass and wind (see below), the actual tax revenue losses may be less than estimated in the CCTI case even if all the projected new capacity enters service. To the extent that new generating capacity (1) is ineligible for the PTC because of minimum tax rules or other requirements effectively disallowing the benefits, (2) enters service later in its initial year or is delayed until a later year, or (3) performs below the 33-percent capacity factor assumed for new wind capacity or the 80-percent capacity factor assumed for new biomass capacity, the tax revenue reductions could be less than estimated here. Wind In the reference case, new wind generating capacity is expected to be built after 1999 despite the expiration of the EPACT PTC. In response to State mandates, renewable portfolio standards, and other requirements, 537 megawatts of new wind capacity is projected to be added from 2000 through 2004. No additional wind capacity is expected to be added in this period based solely on economics. Wind technology costs and performance are expected to improve, but they still are not expected to be competitive with new natural gas plants in most situations. Extending the PTC through 2004 leads to only modest additions of new wind generating capacity beyond those projected in the reference case. In the CCTI case, U.S. wind generating capability is only 50 megawatts above reference case projections (Table 22). The minimal cost declines induced by the addition of this capacity result in little additional wind generating capacity after 2004 and only 10 megawatts more after 2010. The tax revenue consequences of the CCTI are similarly modest for wind power when applied only to the CCTIinduced additional capacity, totaling only $2.6 million in 2005. The total tax revenue effects of the PTC extension are much greater. however, because the 537 megawatts of wind capacity expected to be added in the reference case can also take advantage of it. As a result, if all the eligible plants take advantage of the extended PTC, the cost could reach $28.9 million in 2005. Because little new wind capacity is expected to be encouraged by the extended PTC, carbon emissions are virtually unchanged, decreasing by less than 0.1 percent of electricity sector carbon emissions. Table 22. Projected Effects of the CCTI Wind Energy Production Tax Credit, 2005, 2010, and 2020 1.88 3.24 3.29 3.39 3.44 3.47 3.53 3.41 7.24 7.39 7.69 7.84 7.84 8.14 1,479.6 1,676.3 1,676.2 1,784.3 1,784.2 1,951.8 1,952.0 28.88 22.43 0.00 Wind Generating Capacity (Gigawatts) The PTC could indirectly lead to new capacity additions not captured in the results presented here. Just as the new wind plants added during the EPACT PTC time frame appear to have been encouraged by the combination of the PTC, State mandates, and other incentive programs, the combined stimulus could conceivably continue with the extension of the PTC. Without the PTC extension, the other incentive programs could be less successful. Conversely. green power programs and utility testing programs may grow if the PTC is extended. Some consumers may be willing to pay a small premium to purchase green power, including wind power, but if the PTC is not extended the premium required may exceed what they are willing to pay. Similarly, some power companies have been experimenting with new wind facilities to become familiar with the technology and test how they might use it within their systems. Their willingness to continue those efforts may grow if the PTC is extended. Overall the impacts of the tax incentives for new wind and biomass generating technologies are expected to have very modest impacts. Their combined impact reduces carbon emissions by only 0.5 million tons (less than 0.1 percent of electricity sector carbon emissions) in 2010. In addition, they slightly reduce the costs of complying with SO2 and O, emission caps. While the production tax credits for these technologies do lower the costs faced by potential developers, they are not large enough to overcome the cost disadvantages they face. New gas-fired facilities (and new coal-fired facilities after 2015) are very economical, making it difficult for new wind and biomass plants to break into the market. Even though renewable technologies are improving, the falling costs and improving efficiencies of new fossil generating technologies continue to restrict their penetration in the market. The story for biomass co-firing is somewhat different. Coal plants can burn small amounts of biomass without significant modifications. Thus, if low-cost biomass fuel can be found, collected, and delivered to the plant at reasonable costs, it may be economical. Data suggest that there is a relatively large amount of low-cost biomass available in the form of mill residues, urban wood waste, and site clearing residues. The production tax credit would be expected to encourage power plant operators or third-party developers to search out these supplies and develop collection and handling systems. In 2004, the biomass co-firing PTC is projected to lead to carbon emissions about 3 million tons (0.5 percent of total electricity sector carbon emissions) below the level projected in the reference case. While these PTCs are not expected to spur a large increase in renewable power generation, there are other non-CCTI programs being considered that could have a bigger impact. For example, the Comprehensive Electricity Restructuring Act proposed by DOE in 1998 included a 5.5-percent renewable portfolio standard.60 The AEO99 analysis of this proposal found that it could lead to an annual reduction in carbon emissions of 20 to 25 million metric tons during the 2010 to 2020 period, at a cost of about $1 per month for the average residential household." Conclusion In general, the impacts of the proposed tax incentives in CCTI are relatively small. In 2004, the tax credits for the buildings, industrial, and transportation sectors are projected to reduce total primary energy consumption by 33.5 trillion Btu, or 0.03 percent, relative to the reference case projection of nearly 104 quadrillion Btu (Table 23). The impact in 2010 is 31.6 trillion Btu (0.03 percent). In the reference case, carbon emissions are projected to reach 1,659 million metric tons in 2004 and 1,790 million metric tons in 2010. These tax incentives lower the projected emissions by 1.9 million metric tons (0.11 percent) and 1.6 million metric tons (0.09 percent) in 2004 and 2010, respectively (Table 24). The wind and biomass generation tax incentives are projected to reduce fossil energy consumption for electricity generation by 129.8 trillion Btu in 2004 and by 71.9 trillion Btu in 2010, reducing carbon emissions by 2.9 million metric tons (0.17 percent) in 2004 and by 1.5 million metric tons (0.08 percent) in 2010. In 2004, total carbon emissions are reduced by 4.8 million metric tons, or 0.29 percent, as a total of the individual impacts of the tax credits. The reduction reflects lower energy consumption and a shift in the mix of energy fuels. In 2010, the tax credits reduce carbon emissions by 3.1 million metric tons, or 0.17 percent of the reference case projection. Table 23. Reductions in Energy Use Projected To Result from CCTI Tax Initiatives, 2002-2010 (Trillion Btu) "Cogenerated electricity substitutes for purchased electricity, and total site use increases due to additional natural gas consumption. For the wind and biomass tax credits, the change represents the reduction in fossil energy use for electricity generation. Note: Reductions are relative to the CCTI reference case, which is similar to that in Energy Information Administration, Annual Energy Outlook 1999, DOE/EIA-0383(99) (Washington, DC, December 1998). 60 The bill is currently being revised, and the RPS requirement may change. Energy Information Administration, Annual Energy Outlook 1999, DOE/EIA-0383(99) (Washington, DC, December 1998). |