Greenhouse Gas Concerns and Power Sector Planning |
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Background Concerns about potential climate change driven by rising atmospheric concentrations of GHGs have grown over the past two decades, both domestically and abroad. In the United States, potential policies to limit or reduce GHG emissions are in various stages of development at the State, regional, and Federal levels. In addition to ongoing uncertainty with respect to future growth in energy demand and the costs of fuel, labor, and new plant construction, U.S. electric power companies must consider the effects of potential policy changes to limit or reduce GHG emissions that would significantly alter their planning and operating decisions. The possibility of such changes may already be affecting planning decisions for new generating capacity. California and 10 States in the Northeast are moving forward with mandatory emissions reduction programs. For 10 Northeastern States, 2009 is the inaugural year of the RGGI, a cap-and-trade program for power plant emissions of CO2 [85]. RGGI sets a cap of 188 million metric tons CO2 in 2009 for power generating facilities with rated capacity greater than 25 megawatts and lowers that cap annually to 169 million metric tons in 2018. Although RGGI represents the first legally binding regulation of CO2 emissions in the United States and will influence future decisions about investments in generating capacity, its overall impact is expected to be modest. In 2006, CO2 emissions from power plants covered by RGGI accounted for only 7 percent of the CO2 emitted from all U.S. power plants, and their total 2006 emissions—at 164 million metric tons—already were below the 2018 goal of 169 million metric tons. Other regional initiatives also are being developed. The WCI consists of seven Western U.S. States and four Canadian Provinces [86]. A draft rule released in July 2008 aims at an economy-wide cap on six GHGs, including CO2. The cap level and details of the program design still are being developed. In November 2007, the governors of 10 Midwestern States signed the Midwestern Greenhouse Gas Reduction Accord [87], currently in the preliminary stages of development, with the broad goal of creating a multi-sector, interstate cap-and-trade program for the member States. At the State level, 37 individual States have released State-specific climate change mitigation plans; however, the only legally binding requirements outside the RGGI States are in California, which has passed Assembly Bill (A.B.) 32, the Global Warming Solutions Act of 2006 [88]. A.B. 32 aims to reduce the State’s GHG emissions to 1990 levels by 2020. Although specific regulations associated with A.B. 32 remain to be finalized, the law requires that policies be designed to meet the reduction targets. At the national level, numerous bills to reduce GHGs have been introduced in the U.S. Congress in recent years. As of July 2008, a total of 235 bills, amendments, and resolutions addressing climate change in some form had been introduced in the 110th Congress. Nine of the bills—three in the House and six in the Senate—specifically proposed a cap-and-trade system for CO2 and other GHGs. Of the nine, the Boxer-Lieberman-Warner Climate Security Act (S. 3036) progressed the farthest, reaching the floor of the Senate in June 2008 [89]. Even without the enactment of national emissions limits, many State utility regulators and the banks that finance new power plants are requiring assessments of GHG emissions for new projects. For example, many State public utility commissions now are requiring that utilities review projected CO2 emissions in their integrated resource plans (IRPs) [90]. The IRP process is intended to keep public utility regulators at the State level informed of their utilities’ strategies to meet future demand and supply. The treatment of projected CO2 emissions has differed among utilities. Some have included an emissions price in their base case scenarios; others have done so in alternative scenarios. Typically, the emissions prices used have ranged from $5 to $80 per metric ton. Several major banks in the United States also have decided to include future CO2 emissions as a factor in their decisionmaking processes for financing of new power plants. In February 2008, Citibank, JPMorgan Chase, and Morgan Stanley announced the formation of “The Carbon Principles,” which provide climate change guidelines for advisors and lenders to power companies in the United States [91]. Adopters of the principles would commit to:
Reflecting Concerns Over Greenhouse Gas Emissions in AEO2009 Key questions in the development of the AEO2009 projections included the degree to which ongoing debate about potential climate change policies, together with the actions taken by State regulators and the financial community, already are affecting planning and operating decisions in the electric power sector, and how best to capture those impacts in the analysis. Although existing plants continue to be operated on a least-cost basis without adjustments for GHG emissions levels, concerns about GHG emissions do appear to be having an impact on decisions about new plants. When regulators and banks are reviewing the projected GHG emissions of new plants in their investment evaluation process, they are implicitly adding a cost to some plants, particularly those that involve GHG-intensive technologies. The implicit cost could be represented by adding an amount to the operating costs of plants that emit CO2 to reflect the value of emissions; however, doing so would affect not only planning decisions for new capacity but also future utilization decisions for all plants—something that does not appear to be occurring on a widespread basis in markets today. Alternatively, the costs of building and financing new GHG-intensive capacity could be adjusted to reflect the implicit costs being added by utilities, their regulators, and the financial community. This option better reflects current market behavior, which is focused on discouraging power companies from investing in high-emission technologies. As a result, in the AEO2009 reference case, a 3-percentage-point increase is added to the cost of capital for investments in GHG-intensive technologies, such as coal-fired power plants without CCS and CTL plants. Although the 3-percentage-point adjustment is somewhat arbitrary, its impact in levelized cost terms is similar to that of a $15 fee per metric ton of CO2 for investments in new coal-fired power plants without CCS—well within the range of the results of simulations that utilities and regulators have prepared. The adjustment should be seen not as an increase in the actual cost of financing but rather as representing the implicit costs being added to GHG-intensive projects to account for the possibility that, eventually, they may have to purchase allowances or invest in other projects that offset their emissions. Two alternative cases were prepared to show how the representation of investment behavior in the electric power sector affects the AEO2009 reference case projections, given uncertainty about the evolution of potential GHG policies. In the no GHG concern case, the cost-of-capital adjustment for GHG-intensive technologies is removed to represent a future in which concern about GHG emissions wanes or efforts to implement GHG reduction regulations subside. This case reflects an approach similar to that used for the reference case in past AEOs. In the LW110 case, the GHG emissions reduction policy called for in S. 2191, the Lieberman-Warner Climate Security Act of 2007 introduced in the 110th Congress, is analyzed [92]. This case illustrates a future in which an explicit Federal policy limiting GHG emissions is enacted, affecting both planning and operating decisions. Because the projected impact of any policy to reduce GHG emissions will depend on its detailed specifications—which may differ significantly from those in the LW110 case—results from the LW110 case do not apply to other past or future policy proposals. Rather, projections in the two alternative cases illustrate the potential importance to the electric power industry of GHG policy changes, and why uncertainty about such changes weighs heavily on planning and investment decisions. Findings The imposition of a GHG reduction policy would affect all aspects of the electric power industry, including decisions about the types of plants built to meet growing electricity demand, the fuels used to generate electricity, the prices consumers will pay in the future, and GHG emissions from electric power plants.
Capacity Generating capacity investment decisions in the two sensitivity cases differ from those in the AEO2009 reference case (Figure 23). The overall amounts of new capacity added in the reference case and the no GHG concern case are similar, but there are differences in the mix of plant types built. New coal builds without CCS are higher in the no GHG concern case than in the reference case, as the concern that new regulations might be coming dampens investment in new coal-fired plants in the reference case. On the other hand, new natural-gas-fired plants, which are not as GHG-intensive, are more attractive economically in the reference case. In an environment of uncertainty about future regulation of CO2 emissions, natural gas becomes the primary choice for new capacity additions; without such uncertainty, coal remains the primary choice. Concern about possible new regulations plays a role in the construction of a modest amount of nuclear power and renewable energy capacity in the reference case, but other incentives also influence their selection. It is unclear whether utilities would be willing to incur the high costs of building new nuclear plants in the absence of concerns about potential GHG regulations. The cap-and-trade policy adopted in the LW110 case changes the mix of capacity additions significantly relative to the other cases. The adjusted cost of capital in the reference case increases the cost of building new GHG-intensive facilities but does not change the cost of operating those plants already in service or new plants once they are built. The introduction of an explicit cap on GHG emissions adds a cost to the emissions generated from existing and new facilities, making carbon-intensive coal-fired plants more expensive to build and operate. As a result, approximately 35 percent of the existing fleet of coal-fired plants is retired by 2030 in the LW110 case, and 33 percent more new capacity is added than in the reference case, replacing the retired capacity. The explicit GHG emission constraint results in the construction of a different mix of new capacity additions, with new nuclear power, renewables, and coal with CCS making up a majority of the capacity added. The new capacity additions lead to a significantly different portfolio of generation assets and generation by fuel in 2030. The results show that implementation of the LW110 case would lead to greater use of coal with CCS, nuclear, and renewable capacity; however, there is significant uncertainty around the projections. New coal-fired plants with CCS equipment have not been fully commercialized, and it is unclear when they might be and what they would cost. Similarly, a rapid expansion of nuclear capacity also would present challenges, including uncertainty both about the cost of the plants and about public acceptance of them. There also may be limits to a rapid expansion of renewable generation, because many of the best resources are located far from electricity load centers. Previous EIA analysis has found that, if the expansion is limited, the electricity industry may rely more heavily on new natural-gas-fired plants to reduce GHG emissions, leading to higher allowance costs and higher electricity prices [93]. Generation by Fuel Among the three cases examined, total electricity generation in 2030 is lowest in the LW110 case (Figure 24 and Table 14). The explicit cap raises the price of electricity, which over time slows the growth in demand for electricity, lowering generation requirements. The opposite is true in the no GHG concern case, where lower electricity prices stimulate higher demand for electricity and increase generation requirements. Generation from coal drops the most in the LW110 case. Relative to the AEO2009 reference case, the explicit GHG emission cap reduces the total amount of electricity generated from all coal-fired plants by 33 percent and the amount from coal-fired plants without CCS by 68 percent in 2030, as older coal plants are retired and the marginal costs of units still operating, which must hold allowances, are higher. Despite their high initial capital costs, new coal-fired units with CCS are less expensive to operate than traditional coal-fired plants without CCS, given a tight constraint on CO2 emissions. The shares of renewables and nuclear power in the generation mix also increase significantly in the LW110 case, as low-emissions technologies are added to meet the growing demand for electricity. Electricity Prices Projected electricity prices are lowest in the no GHG concern case, where there is no cap on emissions, and coal-fired plants with relatively low fuel costs continue to dominate the mix of generation (Figure 25). Greater reliance on natural gas in the reference case leads to higher electricity prices when construction of carbon-intensive facilities, including coal-fired plants, is dampened because of uncertainty about possible GHG regulations. An explicit cap on GHG emissions adds an additional cost to the generation of electricity from CO2-emitting sources. To lower emissions in the LW110 case, the industry turns to more expensive resources and allowance purchases to cover remaining emissions. Therefore, electricity generated from fossil fuels becomes more expensive, while higher priced low-emitting sources, such as nuclear, renewables, and coal with CCS, become more cost-competitive. As a result, the cost of generating electricity increases. In 2030, the price of electricity is 22 percent higher in the LW110 case than in the reference case and 26 percent higher than in the no GHG concern case. Emissions The electric power sector is expected to play a major role in any effort to reduce GHG emissions in the United States (Figure 26). The sector accounted for 41 percent of energy-related CO2 emissions in 2007, and its emissions are projected to grow. On the other hand, a wide array of fuels and technologies with various emission levels are used in the electric power sector, providing some flexibility for altering emissions levels without turning to wholly unknown technologies or requiring end-use consumers to purchase any new equipment. Increases in CO2 emissions from the electric power sector are projected to continue through 2030 in the no GHG concern case and the AEO2009 reference case. In the no GHG concern case, emissions are expected to rise as demand for electricity increases and coal’s share of the national generation mix grows to 53 percent in 2030. Emissions also continue to increase through 2030 in the reference case but at a slower rate because of the reduced reliance on coal for generation. In the LW110 case, in contrast, CO2 emissions from the electric power sector are projected to fall significantly over time. In this case, CO2 emissions from the electric power sector in 2030 are projected to be 52 percent below their 2007 level and 57 percent below the level in the reference case.
Contact: Michael Leff/Robert Smith
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