Summary of Assumptions of Illustrative Analysis The following list summarizes the assumptions in the illustrative modeling analysis described in the preceding section on methodology. Efficient and effective domestic trading of emissions allowances. International trading of emissions allowances (within each of three possible blocs). Efficient and effective Annex I trading. Efficient and effective Umbrella trading. Efficient and effective trading with developing countries that adopt emissions targets. Trading across all six categories of greenhouse gases. Autonomous energy efficiency improvement (AEEI) value of 0.96% per year. No banking of emissions allowances to second or later commitment periods. Emissions targets are expressed in terms of all six categories of greenhouse gases. Marginal abatement costs for carbon dioxide from SGM outputs. Marginal abatement costs for non-carbon dioxide greenhouse gases for U.S. Marginal abatement costs for non-carbon dioxide greenhouse gases for other countries assumed to be the same as the costs for carbon dioxide. No emissions mitigation through carbon sinks for any country included in the analysis (see p. 62). No emission reductions from the Administration's electricity restructuring proposal included in the analysis (see p. 64). No emissions reductions from the Climate Change Technology Initiative included in the analysis (see p. 64). No emissions reductions from industries' voluntary plans through the Q30.3 What is the basis for the $20 billion figure cited by you and Dr. Yellen and the Department of Energy regarding electricity restructuring, and does it take into account the EPA proposals cited in Question 19 above on regulating carbon dioxide and other greenhouse gases? A30.3 For a discussion of the derivation of the cost-savings associated with the Administration's electricity restructuring proposal, please refer to Appendix C in the AEA. The Comprehensive Electricity Competition Act Supporting Analysis (July 1998), DOE publication PO-0057, provides a detailed analysis of the economic benefits of the Administration's electricity competition plan. (Appendix C of the AEA and The Comprehensive Electricity Competition Act Supporting Analysis (July 1998), DOE publication PO-0057 follow.) APPENDIX C: POTENTIAL ELECTRICITY RESTRUCTURING COST-SAVINGS The Administration's electricity restructuring proposal provides potential cost- Several sources of important additional savings are not considered in this analysis. First, as pricing becomes more efficient, load shape adjustments from Second, our cost analysis assumes that regulators and firms would not repeat Finally, experience in other sectors suggests that competition will lead to the Fuel Costs, Non-Fuel Operation and Maintenance (O&M) Costs, and Administrative and General (A&G) Costs Fuel Costs, Non-Fuel O&M Costs, and A&G Costs, which together accounted for roughly $94 billion in reported utility costs in 1995, largely reflect the current operations of electric utilities.' Information reported in standard industry filings suggests a wide range of cost experience across reporting units and companies. These data can provide insight into opportunities for cost reduction. Our approach here is to estimate the value of bringing the cost performance of the entire industry up to the standard already demonstrated by top industry performers -- represented in this paper as the average of the top quartile of reported performance. Some of the differences in cost experience clearly reflect circumstances that will not change under competition. For example, coal prices differ according to the distance from low-cost coal supplies; heat rates reflect the vintage, type, scale, and operating rate of plants and pollution control requirements; and distribution costs are systematically related to the density of customers on a system. To account for such factors, we stratified the reported data along key dimensions prior to developing the quartile analysis. Stratification narrows the range of cost variation, but significant differences remain, as reported in Table C2. The reported total of $24.6 billion in cost-saving potential could either underestimate or overestimate actual cost reduction opportunities. On the underestimation side, top quartile performance under regulation may understate achievable efficiencies under competition as even the best current performers re-engineer and rethink their activities. Moreover, the lack of data for existing non-utility generators, which are 1 A portion of A&G costs also reflect historical operations to the extent that pension widely believed to be among the most cost-effective operators, could lead to some underestimation of even the current state-of-the-art efficiencies. On the overestimation side, the stratification underlying the quartiles reported in Table C2 for fuel and O&M costs may fail to account for all sources of irreducible cost differences. Moreover, the portion of the variation in cost across plants that reflects contract cycles for fuel and other inputs could be expected to narrow over time independent of the advent of competition. Dispatch Efficiencies Competition likely will result in improved dispatch efficiencies. The advent of competition will shift the market from a "shared savings" paradigm to one in which the party that identifies a cost-effective trade can reap the benefits, providing dispatch efficiencies beyond those that might result from wholesale competition alone. Analyses using the Policy Office Electricity Modeling System (POEMS) suggest that dispatch efficiencies resulting from retail competition can reduce aggregate system fuel costs by approximately $600 million relative to a scenario reflecting a continued cost-of-service regime. More Efficient Utilization of Capital The generation, transmission, and distribution of electricity are among the most capital-intensive activities in the United States. Yet, the relatively inflexible price signals provided to consumers under traditional cost-of-service regulation have resulted in relatively poor utilization of our substantial investment in electricityrelated capital. Retail competition will allow electricity markets to emulate the experience of airlines and communications providers in implementing load-sensitive pricing regimes, allowing the additional use of electricity in price sensitive applications during off-peak and off-season periods. 2 Ideally, the gains from more efficient capital utilization would be calculated separately for each load segment in each season. Although data on the segmentspecific demand responses to price variation are not available, we can use the impacts of competition on average prices to develop a rough estimate of capital utilization cost-savings. Model results and recent experience with restructuring at the state level suggest that average delivered prices in a restructured industry will be 6 to 9 mills (9 to 13 percent) lower than prices projected under continued cost-of-service regulation, depending upon what provisions are made for stranded cost recovery. Using an 2 An example of such a pricing regime can be found in the telecommunications industry where some firms offer lower prices during off-peak times, such as 5 cents estimate of -0.1 to -0.2 for the price elasticity,' the 9 to 13 percent price drop translates into an increase of between 0.9 and 2.6 percent in electricity sales. The net welfare benefit from these extra sales includes two components. First, there is additional "consumer surplus," which reflects the extent to which the value of the extra electricity to buyers exceeds its price. Second, since extra sales under loadsensitive market pricing do not increase transmission or distribution system costs or stranded costs, any transmission, distribution, or stranded cost charges on these sales are also a net welfare gain. In 1995, the national average for transmission and distribution was 2.38¢/Kwh. For a level of baseline demand of 3.25 trillion kilowatt hours, the estimated net welfare gain from more intensive capital utilization is estimated to fall between $820 million and $2.6 billion. It is important to note again that the estimates in this section focus narrowly on the more efficient use of the baseline capital stock. These estimates do not account for the substantial cost-savings associated with more nimble pricing in curtailing peaks that often necessitate the addition of expensive new capacity. Reduced Capital Costs at Existing Plants Capital additions at existing plants are another area where available data suggest a considerable range of experience across utilities. However, the analysis of such additions can be quite complex. First, a considerable portion of the observed variation in the cost of capital additions per unit of capacity can result from environmental or nuclear regulatory decisions affecting specific units that would not be sensitive to the shift to a more competitive regime. Second, capital additions occur at irregularly spaced intervals, and many plants will have no significant capital additions in a particular year. To address the issue of irregularly spaced capital additions, we focused on average capital additions over a decade rather than additions in a single year. Over the 1985 to 1995 period, reported capital additions at existing power plants averaged approximately $6.3 billion per year, with average additions of $3.1 billion at nuclear plants, $2.6 billion at coal-fired plants, and $0.6 billion at oil and gas steam plants. For present purposes, the most interesting comparisons can be made within the set of coal plants commissioned after 1965 that were operating without scrubbers or NO, controls at the end of the sample period, since capital additions at these plants would not reflect the costs of repowering, emissions control requirements, or nuclear regulation. Assuming that the average of the top quartile of reporting units reflects 3 This represents the percentage change in demand resulting from a 1% increase in |