Before restructuring, electric service was provided primarily by federal- and state-regulated investor-owned electric utilities. A utility typically owned the power plants, transmission system, and local distribution lines that supplied electricity to all of the consumers in a geographic area. Under this system, the Federal Energy Regulatory Commission (FERC) regulated, among other things, sales of electricity for resale and the transmission of electricity over high-voltage power lines in interstate commerce. The states regulated retail markets by participating with utilities in forecasting growth in demand, planning and building new power plants, reviewing and approving utility costs, and establishing rates of return. In response to the enactment of the Energy Policy Act of 1992, FERC has opened wholesale electricity markets across the country, and many states have also opened their retail markets to competition. In these competitive markets, consumers will eventually pay market-based electricity prices, and power plant developers are no longer guaranteed that construction costs will be repaid or that the electricity produced will be sold profitably. In these markets, it was expected that independent developers would individually assess the need for new generation and its potential profitability. These assessments would be made on the basis of market signals, such as the prices of electricity and other related products and forecasts of the generation required to meet growing demand. As shown in figure 1, the U.S. electricity transmission system consists of three connected, but independently operating systems: the western interconnect, the eastern interconnect, and the Texas interconnect. Each of these systems must maintain a constant balance between the amount of electricity supplied by power plants and the amount of electricity being used at homes and businesses. While little electricity moves from one system to another, electricity produced within each system can move throughout the system, subject to transmission system constraints that can limit or prevent the flow of electricity within certain regions of the system. The level of electricity demand varies considerably throughout the day, with the highest levels only reached during a small percentage of the hours during a year. In addition, unlike other commodities, electricity cannot easily or inexpensively be stored and must be instantly available whenever demand increases. Because these systems are interconnected, a change in the supply or demand in one part of the system can affect producers and consumers elsewhere. To ensure that supply exceeds the demand for electricity, utility systems have historically maintained additional power plants, as part of a reserve margin, above the amount needed to meet the highest level of expected demand. This reserve margin has enabled utilities to meet demand when a power plant was taken out of service or when demand rose more than expected. As part of the western interconnect, California has historically imported about 20 percent of the electricity that it consumes. While California’s utilities had owned power plants located in California and other states as part of their supply mix before restructuring, they have since sold most of these plants to private companies not regulated by California. In contrast, in recent years, Pennsylvania has exported more electricity than it has imported. Although some of the power plants owned by the state’s former utilities were sold as a result of restructuring, the plants have long-term contracts to sell electricity in Pennsylvania. Power plants in Texas generate nearly all of the electricity that the state consumes. The state’s utilities have leased access to generating capacity at some of their plants and some have been sold; however, the utility plants that are leased are operated by subsidiaries of the former utilities. As part of its efforts to restructure the industry, FERC issued regulatory orders that require transmission system owners to allow all parties, including new power plant developers, to transmit electricity under comparable terms and conditions. FERC has approved the formation of independent organizations to operate the transmission system in California and other states. An example of this new type of organization is the PJM Interconnect, which operates the transmission system in all or parts of Pennsylvania, New Jersey, Maryland, Delaware, and Washington, D.C. FERC also directed transmission system owners to create multistate regional transmission organizations to operate the systems independently of the transmission owners. To maintain the reliability of the transmission system, transmission owners and operators participate in the North American Electricity Reliability Council (NERC) through 10 regional reliability councils. These regions cooperate in planning and integrating the transmission system and study trends in long-term supply and demand. U.S. electricity markets have attracted significant planned investment to the nearly 770,000 megawatts of generating capacity already on-line at the end of 1995. Through the end of 2001, developers had proposed or added about 690,000 megawatts of new electricity generating capacity, of which about 114,000 megawatts were already built and another 123,000 megawatts were under construction. Industry data indicate that about 104,000 megawatts of proposed plants had been either tabled or cancelled—with the remainder in various stages of planning or development. About 40 percent of the proposed generating capacity was planned for states identified as active in implementing restructured electricity markets, and 20 percent for states that have actively pursued electricity restructuring but have either delayed or suspended further actions. While coal, nuclear power, water (hydroelectric dams), and oil are the primary fuels for older power plants, natural gas-fueled power plants accounted for over 80 percent of the generating capacity added from 1995 through 2001 and a similar percentage of the plants proposed for construction through the end of 2001. About 62 percent of the gas-fired plant capacity proposed through 2001 would use highly energy-efficient combined-cycle technologies, and 35 percent would use simple-cycle technologies. Both types of power plants rely on large gas turbines, also called combustion turbines, with combined-cycle units adding a steam generator and a steam turbine to convert waste heat in the exhaust stream to electricity. In general, both types of plants are more fuel efficient, less costly to operate, and less polluting than many existing power plants. Because of their higher efficiency and relatively low operating costs, combined-cycle power plants are often used to generate electricity through large portions of the day. In contrast, simple-cycle power plants typically are used to generate electricity only during periods of high demand because they cost more to operate. These plants are useful in meeting sudden changes in demand because they can reach full output in as little as 10 minutes. In general, simple-cycle power plants can be constructed in about 6 to 9 months after regulatory approvals, while combined-cycle power plants need from 18 to 28 months. Electricity demand in Texas, California, and Pennsylvania grew faster from 1995 through 2001 than NERC had forecast in 1995. In response, in Texas, developers added the most new capacity—-about 16,200 megawatts, or more than double the forecasted need through 2004. In contrast, in California, developers added about 4,600 megawatts, or 25 percent of the forecasted need for capacity through 2004, and in Pennsylvania, developers added about 2,100 megawatts, or less than half of its forecasted need through 2004. More recently, each state has seen significant cancellations and postponements of projects, with California experiencing the greatest drop. Developers and investment firms noted that events in the past year—the economic downturn, the terrorists’ attacks on September 11, and the collapse of the Enron Corporation— contributed to the cancellation of many proposed projects in the United States and the world. In 1995, when U.S. electricity markets were beginning to restructure, NERC forecast that already planned new plant construction would adequately meet the needs of the regional markets that include each of the three states through 2004. Specifically, NERC forecast the following for each of the reliability regions encompassing the states we reviewed: For California, the 16,800 megawatts of additional planned capacity would adequately meet an estimated 1.8 percent growth in peak demand per year. This added capacity included 13,600 megawatts of generating capacity and 3,200 megawatts of reduced demand to be achieved through the utilities’ conservation and load management programs. For Pennsylvania, the 5,700 megawatts of additional planned generating capacity would adequately meet an estimated 1.3 percent growth in peak demand per year. For Texas, the 6,600 megawatts of additional planned generating capacity would adequately meet an estimated 2.1 percent growth in peak demand per year. Texas’ planned new power plants included 5,300 megawatts of new gas-fueled simple-cycle and combined-cycle power plants. Since NERC’s 1995 report, electricity demand in each market has grown more than expected. Specifically, in 2001, the data for the three reliability regions reflected the following annual average growth: 4.7 percent for California, 2.1 percent for Pennsylvania, and 4.9 percent for Texas. NERC also reported that independent developers would need to continue to add new power plants in order to meet demand over the next 10 years. According to industry data through 2001, developers had announced proposals to build about 118,000 megawatts of new generating capacity in California, Pennsylvania, and Texas—substantially more than NERC’s projection of about 26,000 megawatts by 2004. Figure 2 shows that nearly half of this new capacity was proposed for Texas, while 35 percent was proposed for California and 17 percent for Pennsylvania. In addition, developers generally proposed power plants earlier in Texas than in the other two states. Specifically, 69 percent of the new power plant projects that began the regulatory process in Texas were proposed to regulators before 2000, while 75 percent of the projects in California and Pennsylvania were proposed to regulators in 2000 and 2001. This early interest in entering the electricity market in Texas led to earlier consideration by regulatory agencies involved in the siting approval process. Partly because developers had proposed new power plants earlier, they had built more generating capacity in Texas than in the other two states by the end of 2001. In total, Texas accounted for about 71 percent, or 16,000 megawatts, of the 23,000 megawatts of generating capacity built in the three states from 1995 through 2001.