Winds of change in the U.S. power sector: factors listed in the left column have created a gap between the prices utilities must charge to recover their embedded costs and the lower rates they would have to charge in a competitive environment. Possible responses to these pressures are listed to the right.
The electricity industry in the U.S. is being dramatically restructured by state regulatory commissions and the Federal Energy Regulatory Commission. Efforts are underway to create a wholesale market for electricity, with wholesale prices to distributing utility companies no longer being regulated. Discussions in several states and at the FERC are aimed at revising the regulation of the structure, operation, and pricing of the electricity transmission grid to make it available on comparable terms to all generators and distributors— and perhaps individual customers. LBNL researchers studying this restructuring have shown in general that cost reductions are achievable by modifying the way we regulate electric utilities, that such cost savings will likely come slowly, and that current social goals can be maintained in a competitive, market-based electricity industry with an overall benefit to our country.
Research on restructuring in the Center, largely conducted under DOE's Integrated Resource Planning Program, is spread throughout the Energy Analysis Program. One such project has shown that commercial lighting demand-side management (DSM) programs are economically justified (CBS News, Summer 1994).
Another project focuses on the efficiency of electricity generation and transmission. The 1992 U.S. Energy Policy Act reflects a debate initiated by bond rating agencies on whether long-term power purchase contracts between nonutility generators (NUGs) and utilities are the equivalent of utilities debt and therefore raise the cost of capital to the purchaser, or do these contracts reduce risk to the utilities. Ed Kahn, Steve Stoft, and Tim Belden have approached these questions from the perspective of the equity markets. If NUG contracts really are equivalent to debt, then they raise the risk to the firm and this should be observable in the equity market. The evidence does not support the hypothesis that NUG debt translates to utility debt. Evidence does suggest that utility construction raises the cost of capital more than NUG purchases do. Also, private power prices appear to be coming down. These findings support arguments for the unregulated wholesale pricing of electricity.
DSM can be treated as a "supply resource" and become a competitor in an unregulated or less regulated wholesale supply market. Since 1987, about 35 U.S. utilities have signed long-term contracts with developers of DSM resources (typically energy service companies) to provide a quantity of demand and energy savings at specified prices. DSM bidding programs account for only a small portion of the savings (~5%) achieved by utility DSM efforts nationally, but interest continues to increase. Charles Goldman and Suzie Kito have completed the first comprehensive study of 18 DSM bidding programs. The cost of ten of these programs ranged from 5.4 to 8¢/kWh. They compared the allocation of risks among ratepayers, utility shareholders, DSM developers, and participating or host customers in a prototypical utility rebate program and a DSM bidding program and found that utilities use various contractual mechanisms to mitigate the risks of DSM resources to ratepayers. These risk-mitigation options (including various types of security deposits, damage and penalty provisions, and "regulatory out" and "buy out" clauses) protect ratepayers quite well in situations in which projects fail to develop or energy savings deteriorate over the contract term. Thus, from a policy perspective, DSM bidding programs can have an important role in a restructured industry because they are performance- based— utilities typically pay only for energy savings that are verified over relatively long contract terms.
Alan Comnes and Steve Stoft are investigating the characteristics of new regulatory rate-setting mechanisms as alternatives to total price deregulation. Performance-based ratemaking (PBR), the primary challenger to traditional cost-of-service ratemaking, strengthens financial incentives to improve rates, costs, or other aspects of performance. Comnes reviewed nine proposals for PBR made by "early adopting" gas local distribution companies and found that PBR is most often considered a regulatory alternative when a utility faces competition and restructuring in one or more of its business segments. The most common strategy employed by PBR mechanisms is to weaken the link between a utility's regulated prices and its costs and to rely more on market indicators. Despite its positive benefits found in this research, PBR for energy utilities is not universally accepted as superior to traditional rate-of-return regulation. Future attempts by utilities to use this relatively new approach are likely to prove beneficial.
These research projects and a number of others in the Energy Analysis Program are providing a more solid basis for economically efficient electricity sector restructuring.
Energy Analysis Program
(510) 486-5396; (510) 486-6996 fax
This work is supported by the Office of Utility Technologies, DOE.
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