Source Office of Integrated Analysis and Forecasting, National Energy Modeling System fun KYBASE.D080398A 66 percent of their maximum potential output was needed, however, to meet the 1996 level of demand. Over the next 20 years, as the demand for electricity grows, the utilization of coal-fired plants is expected to approach 80 percent. For new capacity additions, the low capital costs and high operating efficiencies of natural-gas-fired combined-cycle plants make them the most economical choice for most uses. 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 (ie. 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. 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 2020 Source: Office of Integrated Analysis and Forecasting, National Energy Modeling System runa KYBASE D060396A FD24ABV.D0803988, FD09ABY D0803988, and FD03BLW.D0803988. 1950 1960 1970 1980 1990 2000 2010 2020 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 Administration, Annual Energy Rene 1997, DOE/EIA-0384(97) (Washington, DC, July 1998). Projections: Office of Integrated Analysie and Forecasting, National Energy Modeling System nun FD09ABV.D0803988 Source: Office of Integrated Analysis and Forecasting, National Energy Modeling System runs KYBASE.D080388A and FD038LW.D080398B. 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.D0803985, FD09ABY D0803068, 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. 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 2005 Source: Office of Integrated Analysis and Forecasting. National Energy Modeling System nuns KYBASE.D080398A, FD24ABV.D0903988, FD09ABV D0803968, and FD03BLW.00803988. 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 existing 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 illustration only. Table 18. Hypothetical Examples of Levelized Plant Costs at Various Carbon Prices 1981 1983 1985 1987 1989 1991 1993 1995 Source: Form FERC-1, "Annual Report of Major Electric Utities, Licensees, and Other unrecovered costs would be stranded. Most coal plants are fairly old, however, and their construction costs have already been recovered. On the other hand, some plant owners could suffer losses because plants they expected to be profitable might no longer be profitable when carbon prices are imposed. Natural Gas The story for natural gas generation is the opposite of that for coal (Figure 75). As the requirement to reduce carbon emissions tightens and the associated carbon price rises, natural-gas-fired generation becomes more economical than coal-fired generation. In 2010 and beyond, electricity generation from natural gas is between 17 percent and 76 percent higher in the carbon reduction cases than in the reference case projections. Overall, between 1996 and 2020, natural gas generation increases by almost 500 percent in the most stringent carbon reduction cases, and even in the 1990+24% case it Coal Gas and Oil Hydro Other Nuclear Souros Office of Integrated Analysis and Forecasting. National Energy Modeling System runs KYBASE 0090398A, FD24ABV.D0803988, FD09ABV. D0803088, and FD038LW.00803988 |