Introduction 4. Electricity Supply This chapter discusses the electricity supply side options under various domestic carbon emissions reduction cases, particularly the 24-percent-above-1990 (1990+24%). 9-percent-above-1990 (1990+9%) and 3percent-below-1990 (1990-3%) cases. The impacts on electricity sector fuel use, capacity expansion and retirement decisions, electricity prices, and carbon emissions are discussed. In addition, the results of sensitivity cases incorporating alternative assumptions about improvements in technology costs and performance, the potential role for new nuclear power plants, and reducing impacts on the coal industry are also discussed. The effects of demand-side decisions (i.e., consumer appliance choices and usage, as discussed in Chapter 3) that would reduce the demand for electricity are also considered. During the approximately 100-year history of the electricity supply industry, the key fuels used to meet the ever-increasing demand for electricity have changed as new generating technologies have emerged and fuel prices varied (Figure 65). Beginning with small hydroelectric facilities just before the turn of the century. the industry then turned to fossil fuels. Among the fossil fuels, coal has almost always played a major role in U.S. electricity generation, and it remains the dominant fuel today. Oil and natural gas use has varied, depending on their respective prices. In fact, concerns about future oil and natural gas prices contributed to the emergence of nuclear power plants in the 1960s. In today's market, coal-fired power plants produce just over half of the electricity used in the United States, nuclear plants 19 percent, natural gas plants 14 percent, and hydroelectric plants about 10 percent. The remaining 7 percent comes from oil-fired plants and plants using other fuels such as municipal solid waste, wood, and geothermal and wind power. In the reference case, which does not include the Kyoto Protocol, the power generation sector is expected to become more energy-efficient over the next 20 years as new, more efficient power plants are built. At the same time, however, dependence on fossil fuels, especially natural gas and coal, is expected to increase, leading to significant growth in power plant carbon emissions. Coal is expected to remain the dominant fuel as existing plants are used more intensively, but generation from 1950 1960 1970 1980 1990 2000 2010 2000 Note: Data on nonutility generation are not available for years before 1989, but it was small. In 1989, nonutility generation accounted for 6 percent of total U.S. electricity generation Sources: History: Energy Information Administ 1997, DOE/EIA-0384(97) (Washington, DC, July Integrated Analysis and Forecasting, Nat KYBASE.0080398A natural gas is expected to increase rapidly, with gas fired plants making up the vast majority of new capacity additions. Of the major non-carbon-based fuels. hydroelectric generation is expected to change very little, and nuclear generation is expected to decline as older, more costly plants are retired. Looked at another way, while the efficiency of the generation sector. expressed as the amount of energy in terms of British thermal units (Btu) needed to produce each kilowat hour of electricity, is expected to improve, increasing dependence on fossil fuels will lead to more rapid growth in electricity sector carbon emissions than in electricity sales (Figure 66). Without the improvement in efficiency, growth in fossil fuel use would match the growth in fossil-fired generation. Although the costs of non-carbon-based generating technologies have fallen, they still are not widely com petitive with fossil fuel technologies. As a result the most economical options available to electricity suppli ers for meeting the demand for electricity over the next 20 years are existing coal plants and new natural gas plants. In 1995, the average operating cost of coal-fired power plants was 1.8 cents per kilowatthour. Only Electricity suppliers have a variety of options available for reducing their carbon emissions. The degree to which each of the options is employed will depend on the level of reduction required and the resultant carbon price (i.e., the market value of a "carbon emissions permit") that evolves in the marketplace. Many of the options may require a significant financial incentive before they become economically attractive. Among the key carbon reduction options available to electricity suppliers are reducing the use of relatively carbon-intensive power plants (particularly coal-fired plants), increasing the use of less carbon-intensive technologies (mainly natural-gas-fired plants), the use of "carbon-free" technologies (i.e. wind, solar, biomass, geothermal, and nuclear), improving the operating efficiencies of existing plants, and investing in demand-side technologies that reduce electricity consumption. In the short run, before a large number of new plants can be built, power suppliers will have to reduce carbon emissions by increasing the use of less carbon-intensive plants. For example, in today's market, most oil and natural gas steam plants are not used very intensively because of their relatively high operating costs. If carbon reduction efforts are made, however, their use is likely to increase, because they produce less carbon per kilowatthour than do coal-fired plants. In the longer run, power suppliers are more likely to turn to new, less carbon-intensive or carbon-free plants. In this analysis, electricity producers are assumed to have 15 new generating technologies to choose from when new resources are needed, or when it is no longer economical to continue operating existing plants (Table 16). The lead times in the tables represent the time needed for site preparation and construction. Environmental licensing may take longer in some cases. The first-of-a-kind costs represent the cost of building a plant when the technology first becomes available, which tend to be relatively high until experience is gained with the technology. The nth-of-a-kind costs represent costs for technologies when they have matured. For technologies that are already considered mature, the two costs will be the same. Investors in the generation market are assumed to make their decisions by reviewing each technology's current and future capital, operations and maintenance, and fuel costs. Both current and expected future costs are considered, because generating assets require considerable investment and last many years. Therefore, developers are assumed to evaluate the costs of building and operating a plant for 30 years when making their decisions. If the Kyoto Protocol is enacted, developers will also have to consider the relative level of carbon emissions from each technology, as well as the expected carbon prices. Depending on the carbon price, the economic decision could be tilted toward technologies that emit less carbon per unit of electricity produced. Overall, because of the relatively wide variety of options available to them, electricity suppliers are expected to account for a disproportionately large share of projected carbon reductions. Nationally, to meet an emissions target 9 percent above 1990 levels, overall carbon emissions in 2010 would have to be reduced by 18 percent from their projected level in the reference case, which is 33 percent above 1990 levels. But in order to meet the target, emissions from the electricity sector in the 1990+9% case are reduced by 39 percent in 2010 relative to the reference case (Figure 67). The situation is similar in the 1990-3% case: electricity sector carbon emissions in 2010 are 54 percent lower than the reference case level. The reduction in carbon emissions is projected to be accomplished through a combination of fuel switching. improvements in end-use efficiency, and improvements in generator efficiency (Figure 68). In the carbon reduction cases, carbon emissions in the electricity sector are projected to begin falling even before the enactment of the Kyoto Protocol, because power plant developers are assumed to consider future costs in their investment decisions. As the implementation date of the Kyoto Protocol approaches, it is assumed 54 Capital costs are assumed to be recovered over the first 20 years of this period. 57-713 99-42 Table 16. Cost and Performance Characteristics of New Fossil, Renewable, and Nuclear Cacause geothermal cost and performance parameters are specific for each of the 51 sites in the database, the value shown is an average for the capacity built in 2000. $ Because municipal solid waste does not compete with other technologies in the model, these values are used only in calculating the average costs of electricity. "Solar thermal is assumed to operate economically only in Electricity Market Module regions 2, 5, and 10-13, that is, West of the Mississippi River, because of its requirement for significant direct, normal insulation.*** *Capital costs for solar technologies are net of (reduced by) the 10 percent investment tax credit. kW = kilowatt. kWh = kilowatthour. MW = megawatt. MWh = megawatthour. NA = not available. O&M = operations and maintanance costs. ** Sources: Most values are derived by the Energy Information Administration, Office of Integrated Analysis and Forecasting from analysis of reports and discussions wit various sources from industry, govemment, and the National Laboratories, with the following specific sources: Solar Thermal-California Energy Commiss Memorandum, Technology Characterization for ER94 (August 6, 1993). Photovoltaic-Electric Power Research Instituta, Technical Assassmart Buck, EPRI-TAS 1993. Municipal Solid Waste EPRI-TAG 1993. that developers will incorporate their expectations of carbon prices into their plans for new capacity additions, and that more lower-carbon generating capacity will be brought on line than would have been in the absence of the expected carbon reduction mandate. Trends in Fuel Use and Generating Capacity To reduce power plant carbon emissions in the 1990+9% case, the mix of fuels used to produce electricity is expected to change significantly from historical patterns (Figure 69). The change required is possible, but it will be challenging. For example, the shift required to stabilize carbon emissions 9 percent above 1990 levels is unprecedented historically. Even during the 1960s and 1970s, when nuclear generation grew rapidly, the change in fuel use patterns was not as dramatic as would be required in this case. In the 1990+24% case, the shift is less pronounced, but coal-fired generation still is projected to be 17 percent lower in 2010 and 40 percent lower in 2020 than in the reference case. Across the carbon reduction cases, the projections show a consistent shift away from coal to natural gas and renewables for electricity generation. In addition nuclear generation remains near current levels, and the demand for electricity falls as the carbon reduction goal tightens (Figure 70). The shift away from coal-fired generation occurs because coal accounts for such a large share of power plant carbon emissions. In 1996, coal-fired power plants Source: Office of Integrated Analysis and Forecasting National Energy Modeling System runs KYBASE.D080398A and FD03BLW.D0803988. produced an estimated 92 percent of the carbon emissions in the power generation sector. In the reference case, that share is expected to be 86 percent in 2010; and in 2020, even though natural-gas-fired generation grows rapidly, coal plants still are expected to account for 81 percent of total carbon emissions from the electricity sector. Per unit of fuel consumed (Btu), coal plants emit nearly 80 percent more carbon than do natural gas plants, and the difference is even greater per megawatthour of electricity generated (Table 17). New natural gas combined-cycle plants are much more efficient than existing coal plants, requiring less than two thirds the amount of fuel (in Btu) to produce a kilowatthour of electricity. As a result, per megawatthour of electricity Source: Office of Integrated Analysis and Forecasting, National Energy Modeling System runs KYBASE.D080398A, FD24ABV D0803968, FD09ABV. D0803988, and FD03BLW.D0803988 produced, existing coal plants release nearly 3 times as much carbon into the atmosphere as do the most efficient new natural gas plants. Coal Generation In the carbon reduction cases, the projected decreases in coal-fired electricity generation are dramatic. In the 1990+24%, 1990+9%, and 1990-3% cases, coal-fired generation in 2010 is expected to be 18 percent, 53 percent, and 75 percent lower, respectively, than in the reference case (Figure 71). In 2020, the differences from the reference case are even larger: 41 percent in the 1990+24% case, 77 percent in the 1990+9% case, and over 96 percent in the 1990-3% case. In 1990-3% case, coalfired generation is virtually eliminated. Coal plants simply are not very economical when carbon prices are high. Such reductions in coal use would come at a cost. Although they are major carbon emitters, existing coal plants are very economical, and their operating costs have been falling (Figure 72). Under more stringent emissions reduction targets, however, with rising carbon prices, the economics of coal-fired generation would change (Table 18). For a power supplier deciding whether to continue operating an existing coal plant, build a new coal plant, build a new natural-gas-fired combined-cycle plant, or convert an existing coal-fired plant to natural gas, continued operation of the coal plant would be a clear winner in the absence of a carbon price. As the carbon price rises, however, the new natural gas plant looks more attractive. In the hypothetical example, assuming a 70-percent capacity factor for the four types of plant, it would make sense to shut the coal plant down and build a new natural gas plant at a carbon price of approximately $100 per metric ton of carbon." Assuming a 30-percent capacity factor, the crossover point would be closer to $200 per metric ton of carbon. In this hypothetical example, the carbon prices that would induce power suppliers to retire existing coal plants are high, because the operating costs of most existing coal plants are low. In reality, the crossover point would vary from plant to plant. 55 Generating Capacity In all the carbon reduction cases, significant amounts of coal capacity are expected to be retired (Figure 73). In general, the projected changes in the mix of generating 2015 Source: Office of Integrated Analysis and Forecasting National Energy Modeling System runs KYBASE.D080398A, FD24ABY D0803988, FDOSARY D0803988, and FD038LW.D0803998 capacity parallel the changes in fuel use. As the domestic carbon reduction requirement becomes more stringent, more coal capacity is retired and more natural gas and renewable plants are built (Figure 74). In the 1990+24% and 1990+9% cases, there is 3 percent and 10 percent less coal-fired capacity by 2010, and 13 percent and 36 percent less by 2020. Approximately two-thirds of the exist ing coal-fired capacity is projected to be retired by 2020 in the 1990-3% case. The net result is that the share of capacity accounted for by coal plants declines from around 40 percent in 1996 to just over 29 percent in 2010 and to slightly over 11 percent in 2020 in the 1990-3% case. One possible effect of the projected coal plant retirements is that some of the plants may be shut down before their total investment costs are recovered. Such 55 In NEMS, the capacity factor for a particular plant type is determined by its operating costs. The values presented here are for illustra tion only. |