Delivery of electricity requires adequate generation capacity and supply and the ability to move that electricity to its end users. Most discussions concerning electric reliability involve the bulk power electric system and the degree to which its performance affects the continuity of a power supply to its customers. Under a regulated electric utility industry, the state public utility commissions (PUCs) could require generating utilities to maintain a specified reserve margin for the generating capacity as well as adequate transmission capacity. Under a restructured system, only the transmission and distribution components of the system will be regulated. The state PUCs will not be able to require certain reserve margins for generators.
The move towards a restructured electric utility industry has apparently contributed to decreased reliability of electricity in some regions of the country. Under market-based supply of electricity, excess generating capacity is a commodity to be sold. To improve the financial bottom-line of generating companies and to meet basic demand, a greater portion of generating capacity is now being used for generation rather than reserves for reliability purposes. According to the North American Electric Reliability Council (NERC), capacity margins are at the lowest levels in many years, particularly in the Eastern Interconnection. In the next two years, more than half of the announced utility and non-utility generation additions are needed just to keep pace with demand growth, according to NERC. As a result of these pressures on generation capacity, certain areas of the country have recently experienced supply shortages. One effect of generation shortages has been increased interest by electric consumers in generating their own power, so-called distributed generation.
If adequate regional transmission capacity exists, local supply shortfalls could be mitigated by moving excess power from another location. However, the electric transmission system in the United States was developed to support local reliability through a regulated wholesale power market that dealt primarily in intrastate transactions. It was not designed to deal with the magnitude of large-scale interstate bulk-power transfers that have resulted from state restructuring activity.
At the same time that the regulatory structure has been changing, electricity demand has increased, but investments in transmission infrastructure have not kept pace. Nationwide, electricity demand has increased 30% since 1990 while transmission capacity has increased only 10%. The reluctance of electric utilities to invest in transmission infrastructure as well as generating capacity is partially explained by the uncertainty of the future regulatory regime. In addition, some argue that the proper incentives do not exist for transmission companies to invest in infrastructure. Third, siting of new transmission lines is often difficult because of environmental and other concerns.
The movement from pricing based on the average cost of generating electricity in regulated markets to marginal cost pricing in competitive markets has a number of implications for both consumers and suppliers. With average cost pricing, variations in operating costs across seasons and times of day are not apparent to most consumers. With competitive pricing, consumers may see more price volatility in the form of time-of-use prices, which will vary with the cost of producing power. In order for a truly deregulated generation market to operate, however, both the providers and the users of the commodity must receive the proper price signals. For the suppliers, higher prices might signal an opportunity to build additional generating capacity. Without accurate price signals, sufficient transmission and generation additions may not be built. For the consumer, improved pricing information and metering would allow consumers to vary their load.
The lack of adequate price signals and regulatory uncertainty has contributed to brown-outs and price spikes in several regions of the country. Most notably, power outages and other system disturbances in the Midwest and California have increased during the past two summers. In California, the Public Utility Commission (PUC) and the Independent System Operator (ISO) have recently imposed price caps on electricity. An ISO is a neutral operator responsible for maintaining instantaneous balance of the grid system. The ISO performs its function by controlling the dispatch of flexible plants to ensure that loads match resources available to the system. The ISO set a price cap for peaking power and the PUC limited the amount that San Diego Gas and Electric (SDG&E) may charge for first 500 kilowatt-hours (kWh) per month for residential customers and for the first 1,500 kWh for commercial customers.
The Federal Energy Regulatory Commission (FERC) is currently studying the California situation to determine if the markets are operating efficiently as the industry transitions to a more competitive marketplace. In addition, California's Governor Davis signed two bills into law on September 6, 2000 that address the San Diego price spikes. One bill set a rate cap for certain SDG&E customers, and the other provides for an expedited permit process for new power plants.
In theory, such price spikes would encourage investment and improved reliability although in the short-term they may create hardships for consumers. However, by imposing price caps, the regulators may be sending a contradictory message. Many analysts believe that the California price spikes are most likely caused by a combination of factors including transitional pricing issues and regulatory uncertainty which has resulted in an unwillingness to invest in generation and transmission capacity. Consumer groups argue that consumers should not be responsible for paying volatile electric bills that are the result of a poorly conceived electric market and that the rate cap does not go far enough.
The Department of Energy issued its final report in March 2000 on its findings and recommendations to enhance electric reliability. The report recommends 12 areas for federal government involvement:
Several legislative proposals would mandate bulk-power system users' participation in an Electric Reliability Organization (ERO). The ERO would need the Federal Energy Regulatory Commission (FERC) approval for its organization structure as well as its reliability standards. Additions to the generation and transmission system are a large part of a long-term solution to the electric reliability issue. Without the ability to move electric power to the demand centers, continued near-term disruption in service is likely. However, these proposals do not currently include provisions to encourage investment in generation and transmission.
Report of the U.S.
Department of Energy's Power Outage Study Team
Findings and Recommendations to Enhance Reliability from the Summer of 1999
Power Quality Considerations for Distributed Generation
Renewing the North American Electric Reliability Oversight System
North Electric Reliability Panel
Final, Prepublication Copy, December 22, 1997
Current System Conditions, supplied by NERC
1999 NERC Reliability Assessment
Federal Reporting Requirements For: Major System Incidents on Electric Power Systems
Financial Implications of the Competitive, Marginal Cost
Pricing of Electricity Generation
Reliability. In the bulk power system, reliability is the degree to which the performance of the elements of that system results in power being delivered to consumers within accepted standards and in the amount desired. The degree of reliability may be measured by the frequency, duration, and magnitude of adverse effects on consumer service. The two basic functional aspects of the bulk power system are adequacy and security. Adequacy is the ability of the bulk power electric system to supply the aggregate electric power and energy requirements of the consumers at all times, taking into account scheduled and unscheduled outages of the system components. Security is the ability of the bulk power system to withstand sudden disturbances such as electric short-circuits or an unanticipated loss of system components.
Bulk Power Supply. Often this term is used interchangeably with wholesale power supply. In broader terms, it refers to the aggregate of electric generating plants, transmission lines, and related-equipment. The term may refer to those facilities within one electric utility, or within a group of utilities in which the transmission lines are interconnected.
Reserve Margin. The amount of unused available capability of an electric power system at peak load for a utility system as a percentage of total capability. Capability is defined as the maximum load that a generating unit, generating station, or other electrical apparatus can carry under specified conditions for a given period of time without exceeding approved limits of temperature and stress.
Page last updated October 13, 2000.