The Army Corps of Engineers (the “Corps”) and the Department of the Interior’s Bureau of Reclamation (the “Bureau”) operate about 130 hydropower plants at dams throughout the nation. These plants generate electricity from the flow of water that is also used for other purposes, including fish and wildlife enhancement, flood control, irrigation, navigation, recreation, and water supply. Since about the 1930s, electricity that is generated by these hydropower plants has played an important role in electricity markets. These plants were a key element in electrifying rural and sparsely populated areas of the nation. These plants account for over 35,000 megawatts (MW) of generating capacity (or about 5 percent of the nation’s total electric supply) in 1998. The Department of Energy’s power marketing administrations (PMA) generally market the electricity generated at these plants to wholesale customers (the “power customers”), such as rural electric cooperatives and municipal utilities, that in turn sell the electricity to retail customers. (Fig. 1.1 shows the service areas of the PMAs.) Revenues earned from the sale of this electricity totaled over $3 billion in fiscal year 1997. These revenues pay for the operation and maintenance of the government’s electricity-related assets and repay a portion of the outstanding federal appropriated and other debt of about $22 billion for the Bureau’s and the Corps’ power plants, related PMA transmission lines, and well as certain related federal investments for irrigation, water supply, and other facilities that are to be repaid over time from electricity revenues. The revenues also pay interest on the outstanding appropriated debt, where applicable. In traditional markets, electric utilities enjoyed relative certainty about the amount of demand they would have to satisfy in the future. A compact existed between utilities and state public utility commissions. Utilities were obligated to serve all existing and future customers in their pre-established service areas. In return, utilities were granted monopolies within their service areas and approved rate schedules that guaranteed stated earnings on their operating costs and investments. They forecasted the load they would serve by using econometric and end-use analyses models over future periods of time that were as long as 20 years. They collected sufficient funds in their electric rates to pay for needed generating capacity and to operate, maintain, and repair existing power plants and other electricity assets. The funds collected through rates also include profits. However, the nation’s electricity markets are undergoing significant changes. The Energy Policy Act of 1992 significantly increased competition in wholesale electricity markets. In addition, competition at the retail level is now arriving. According to the Department of Energy’s Energy Information Administration, as of March 1999, 18 states had acted—by legislation that had been enacted (14 states) or by regulatory order (4 states) —to restructure electricity markets. Regulators in these states expected that industrial, commercial, and, ultimately, residential consumers would be able to choose their electricity supplier from among several competitors, rather than being tied to one utility. As competition increases, the rates paid by consumers for electricity have dropped and should continue to do so. For example, according to the Energy Information Administration, as a result of such factors as emerging competition and new, more efficient generating technologies, retail electricity rates decreased by about 25 percent from 1982 through 1996, after factoring in the impact of inflation. The administration expects electricity rates to continue to decrease in real terms by 6 percent to 19 percent by 2015. In recent years, uncertainty about the pace and extent of competitiveness in electric markets has caused utilities to be more flexible. Utilities have relied more on purchasing electricity from other sources or acquiring new power plants, such as smaller natural-gas-fired plants, that are less expensive and more flexible for meeting shifting demand. They have also cut costs by reorganizing and reducing staff, and they have consolidated or merged with other utilities where they believed it was appropriate. For example, after years of virtually no mergers, from October 1992 to January 1998, investor-owned utilities had proposed over 40 mergers and completed 17 of them, according to the Edison Electric Institute. In addition, according to utility officials, some utilities are retiring or divesting some high-cost power plants, while others are buying those same plants to serve a niche in their resource portfolios. According to utility officials, in more stable electricity markets, utilities and federal agencies maintained and repaired their hydroelectric and other power plants according to a schedule that was predetermined by the manufacturer’s specifications and the operating history of the plant. Maintenance and repairs were frequently made at this predetermined time whether or not they were needed. Because maintenance or repairs could have been performed later or less frequently, perhaps with lower costs, some Bureau and utility officials that we contacted characterized these practices as over-maintenance of the hydropower plants. These practices, according to an industry consultant, were seldom questioned partly because of the low costs and resiliency of hydropower plants—especially of those placed into service during the 1950s. However, as markets become more competitive, federal agency, utility, and electric industry officials have increasingly viewed hydropower plants as particularly useful to utilities’ overall operations. One of hydropower’s important traits is its flexibility in meeting different levels of demand. This characteristic, according to utility officials, means that hydropower plants will likely continue to play a significant role in meeting demand during peak periods and providing ancillary services, without which electricity systems cannot operate. Currently, utilities provide these services routinely. However, according to Bureau, PMA, and utility officials, depending upon actions taken by federal and state regulators in the near future, a separate market may develop for ancillary services. These services may be priced separately and may allow utilities with hydropower to capture a market niche and earn additional revenues. In response to new markets and perceptions about the role of hydropower in those markets, federal agencies and some utilities have reconsidered how they operate, maintain, and repair their hydropower plants. For example, some utilities have implemented less-expensive, more-flexible maintenance practices, which consider such factors as the generating size of a utility’s hydropower plants, those plants’ roles in the utility’s generation portfolio, and marketing and economic considerations. One such approach, called “Reliability Centered Maintenance,” is defined as a maintenance philosophy that attempts to make use of the most logical, cost-effective mix of breakdown maintenance, preventive maintenance, and predictive testing and proactive maintenance to attain the full life of the equipment, reduce maintenance costs, and encourage reliable operations. For example, according to some utilities we contacted, in determining when to maintain or repair equipment, they are relying increasingly on the use of monitoring equipment to detect changes in the operating conditions of the equipment, instead of performing those actions in a prescheduled manner, as in the past. On the basis of these examinations, the utility may decide to repair or replace the component. Alternatively, the utility may decide to stretch out the operation of the component to the point of near-failure. Some components may actually be run until they fail. However, according to Corps and utility officials, in the cases of some smaller hydropower units, installing monitoring equipment at a cost of $200 to $500 per unit may not make economic sense. Other measures may also be used to monitor the operating condition of equipment. For example, the Corps tests the lubricating oil to indicate the condition of its generating equipment. Also, in some cases, when deciding how and when to maintain and repair generating units, management now considers the plant or the unit as an individual cost center that must make a positive contribution to the utility’s bottom line. In such an environment, plant managers will become more aware of the production costs and will exert increased pressures to cut costs at the plant and at the corporate levels. Plant managers may become aware that a utility may actually shut down and sell a generating unit if operating or repairing it does not return a required, positive financial return. As market competition intensifies, utilities will face increasing pressures to operate as efficiently and cost-effectively as possible. Utilities’ management will need to know how well their plants are producing electricity in order to make informed decisions about how to allocate scarce dollars for maintaining and repairing power plants, where to cut costs, or, in more extreme cases, which generating units to sell or shut down. An important concept for defining power plants’ performance is the “reliability” with which plants generate electricity. Within the electric utility industry, power plants are viewed as “reliable” if they are capable of functioning without failure over a specific period of time or amount of usage. The availability factor and the related outages factors are widely accepted measures of the reliability of power plants. The time a generating unit is “available” to generate electricity is the time it is mechanically able to generate electricity because it is not malfunctioning unexpectedly or because it is not being maintained or repaired. For instance, if a unit were available to generate electricity 8,000 hours out of the 8,760 hours in a year, then its availability factor would be 8,000 hours divided by 8,760 hours, or about 91.3 percent. When a unit is unable to generate electricity because it is broken, being repaired, or being maintained, it is in outage status. Outages are further classified as “scheduled” outages if the unit is unable to generate electricity because it is undergoing previously scheduled repairs or maintenance. If a unit is unable to generate electricity because of an unexpected breakdown and/or if unanticipated repairs need to be performed, then it is in “forced outage” status. If a plant were in scheduled outage status for 100 hours over the course of one year, then its scheduled outage factor would be 100 hours divided by the 8,760 hours in a year, or 1.1 percent.