The federal government owns and operates numerous multipurpose water projects, many of which generate electric power. This power, which is generated subject to the needs of the project, is sold through five federal power marketing administrations (PMA)—the Southeastern Power Administration (Southeastern), the Southwestern Power Administration (Southwestern), and the Western Area Power Administration (Western) as well as the Alaska Power Administration and the Bonneville Power Administration. The PMAs are separate and distinct organizational entities within the Department of Energy (DOE). They are required to market hydropower primarily on a wholesale basis at the lowest possible rates consistent with sound business principles. By law, the PMAs give preference in the sale of federal power to public bodies and cooperatives (called “preference customers”), such as federal agencies, irrigation districts, municipalities, public utility districts, and other public agencies. Each PMA has its own specific geographic boundaries, federal water projects, statutory responsibilities, operation and maintenance responsibilities, and statutory history. In 1995, the three PMAs in our study—Southeastern, Southwestern, and Western—sold about 1.6 percent of the nation’s electricity. A federal water project consists of several resources, such as the dam, the reservoir, the land around the dam and reservoir, and, where hydropower is generated, the powerplant. In addition to providing hydropower, the dams at which hydropower plants are located serve a variety of other purposes, such as promoting fish and wildlife conservation and habitat enhancement and providing flood control, irrigation, navigation, recreation, water supply, and improved water quality. Each project must be operated in a way that balances its multiple purposes. In most instances, because generating power is not the project’s sole purpose, the amount of hydropower generated and marketed is affected by the availability and use of water for the project’s other purposes. The PMAs generally do not own, operate, or control the facilities that actually generate the electric power; almost always, they own, operate, and control the facilities that transmit power, and they market the power that is generated at the federal water projects. The power-generating facilities are controlled by other federal agencies—most often by the Department of the Interior’s Bureau of Reclamation (Bureau) or the Department of the Army’s Corps of Engineers (Corps)—referred to as “operating agencies.” Appendix II lists and describes various laws that guide the Bureau’s and the Corps’ management of federal water projects and hydropower plants. The federal power marketing program, which began in the early 1900s, has developed incrementally over the years. In 1937, the Bonneville Project Act created the Bonneville Power Administration to market federal power in the Pacific Northwest. In 1943, a decision by the Secretary of the Interior established Southwestern under the President’s war powers. The Congress provided the authority to create permanent PMAs with the passage of the Flood Control Act of 1944. The Secretary of the Interior established Southeastern in 1950 and the Alaska Power Administration in 1967. The last PMA, Western, was authorized under the DOE Organization Act of 1977 when the four existing PMAs were transferred from the Department of the Interior to DOE. Many hydropower plants provide electric power for the multiple needs of a federal water project, and the project’s operations have first priority for using it. The PMAs sell the hydropower that exceeds the project’s operational requirements on a wholesale basis to their preference customers and use the revenue earned to repay the costs to generate, transmit, and market power. Revenues from the sale of hydropower are also used to pay for a portion of the irrigation costs assigned for repayment through these revenues where the project serves irrigation. The sale of federal hydropower has also served social and economic development goals. This power is required to be sold at rates that are as low as practicable, consistent with sound business principles, to encourage its widespread use. The PMAs helped make electricity available for the first time to many consumers who lived in rural areas. Nonfederal hydropower projects also generate electricity subject to their multiple purposes. The Federal Energy Regulatory Commission (FERC) licenses and regulates these projects and their hydropower plants that affect the nation’s navigable waterways. FERC’s operating licenses for these hydropower plants are in effect for up to 50 years, after which relicensing must occur. Under provisions of such legislation as the Federal Power Act, as amended by the Electric Consumers Protection Act, FERC’s licensing and regulatory activities establish the conditions under which the project must operate, consistent with legal and policy developments. In licensing and relicensing nonfederal hydropower projects, FERC is required to give equal weight to both “developmental factors” (such as power, irrigation, and flood control) and “nondevelopmental factors” (such as protecting fish and wildlife habitat, conserving energy, and providing recreation). FERC’s regulatory activities with respect to electricity from the PMAs are limited to the authority delegated to it by the Secretary of Energy. FERC’s review of the PMAs’ rates is limited to (1) whether the rates are the lowest possible consistent with sound business principles; and (2) whether the revenues generated by the rates are enough to recover, within the period allowed, the costs of producing and transmitting electricity, including the repayment of the capital investment allocated to generate power and the costs assigned by acts of the Congress for repayment. FERC’s review also includes the assumptions and the projections used in developing the rates. Other than reviewing the PMAs’ rates, FERC has no jurisdiction over the operation of federal hydropower facilities. Each year the Congress appropriates money to the PMAs, the Bureau, and the Corps. The PMAs’ appropriations are generally to cover operations and maintenance (O&M) expenses associated with their power marketing activities and capital investments in their transmission assets. The Bureau’s and the Corps’ appropriations are for all aspects of the federal water projects, including capital investments as well as operation and maintenance (O&M) expenses related to generating power and to providing other functions, such as irrigation and navigation. Federal law calls for the PMAs to set power rates at levels that will repay their appropriations and the power-related O&M as well as the capital appropriations expended by the operating agencies generating the power. DOE’s implementing order specifies that appropriations used for O&M expenses must be recovered in the same year the expenses were incurred; however, it allows the appropriations used for capital investments to be recovered, with interest, over periods that can last up to 50 years. The order also allows the PMAs to defer payments on O&M expenses if the PMAs do not generate sufficient revenue in a particular year because of the variability of hydropower. Because O&M expenses that are deferred are amortized with interest, the amount of deferred expenses accrues interest until it is fully repaid and may require the PMA to increase its rates. The federal investment in water projects has nonreimbursable and reimbursable components. The nonreimbursable component refers to costs that are not reimbursable by revenues collected from the projects’ beneficiaries. The reimbursable component refers to costs that are recovered from the project’s ratepayers and other beneficiaries, such as power and irrigation users. This component includes the construction costs as well as the O&M expenses for power generation, transmission, and marketing; the construction costs allocated to irrigation and O&M expenses for irrigation, if applicable; and the construction costs allocated to municipal and industrial water supply as well as the related O&M expenses. The reimbursable component is further divided into investments repaid with interest (for example, for power and municipal and industrial water supply) and investments repaid without interest (for irrigation only). In 1986, the executive branch first attempted to sell a PMA when the President’s budget proposed selling the Alaska Power Administration to its preference customers. Despite the enactment of laws in 1995 and 1996 to authorize this transaction, the sale of the hydropower assets from which the Alaska Power Administration markets its power has not been completed, in part because of the need to resolve issues related to rights-of-way and easements. The length of time taken to complete the sale of the smallest of the five PMAs raises questions about the complexity and number of issues that will need to be addressed before the government can divest itself of the larger PMAs and their related hydropower assets. Numerous bills have been introduced to the Congress to sell the remaining PMAs, and some bills have included the sale of the related hydropower assets of the Bureau and the Corps. These bills have proposed selling only the PMA and its assets; the PMA and the related hydropower assets of the Bureau and the Corps; or all of these assets plus the related dams and reservoirs. For example, in 1996 legislation introduced in the House of Representatives proposed to divest, among other things, the PMAs and the associated power-generating assets through a competitive bidding process. The bill proposed that FERC be directed to grant a 10-year operating license to the buyers of the federal hydropower plants. It also exempted the divestiture from certain federal laws pertaining to the disposal of surplus federal property and to environmental protection, such as the Federal Land Policy and Management Act of 1976, the National Environmental Policy Act of 1969, the Endangered Species Act of 1973, and the Wild and Scenic Rivers Act of 1968. In response to divestiture proposals, on January 18, 1996, 39 Members of Congress requested that we examine the issues related to the divestiture of the PMAs and related federal hydropower assets. On March 1, 1996, we received a separate request letter from another Member of Congress. We agreed to report on the issues related to divesting the federal hydropower assets, including the PMAs; however, we did not evaluate whether or not the PMAs and federal hydropower assets should be divested. We agreed to provide information on (1) Southeastern, Southwestern, and Western, including their similarities and differences, and their interactions with the agencies that operate federal water projects (mostly, the Bureau and the Corps); (2) the main objectives and general decisions involved in divesting federal assets, along with how these objectives and decisions apply to the PMAs; and (3) the specific issues related to hydropower that should be addressed before a divestiture of the PMAs. As requested, we limited our study to Southeastern, Southwestern, and Western. We did not include the Bonneville Power Administration because it has a unique financial situation or Alaska because it is being divested. A detailed description of our objectives, scope, and methodology is contained in appendix I. We conducted our review from May 1996 through February 1997 in accordance with generally accepted government auditing standards. We provided a draft of this report to DOE (including the PMAs’ liaison office), the Department of the Interior (including the Bureau), FERC, and the Department of Defense (including the Corps). DOE, Interior, and FERC provided us with their written comments. These comments and our responses are included in appendixes VI, VII, and VIII, respectively. We met with officials of the Department of Defense, including the Corps’ Director of Hydropower Operations and the Director of Operations, Construction, and Readiness. Defense stated that our report provided a good assessment of the issues related to the “very complex and controversial” subject. Defense also provided clarifying comments that we incorporated into our report as appropriate. For example, Defense stated that the report needed to be revised to acknowledge that the Corps has improved the generating availability of its hydropower plants in its South Atlantic Division (Atlanta, Georgia) to over 90 percent for fiscal year 1996. While differing in size, scope, and assets, Southeastern, Southwestern, and Western all are responsible for selling hydropower primarily to preference customers—publicly owned utilities and state and federal agencies. These customers vary in size and in the quantity of electricity they purchase. The PMAs have a close working relationship with the Corps and the Bureau because, with a few exceptions, the Bureau and the Corps are responsible for operating the hydropower plants and for ensuring that electricity is generated subject to the other multiple purposes of each federal water project. This relationship is based in part on written documents and also on flexible arrangements that recognize the variability associated with water. The PMAs generally market power to publicly owned utilities and to state and federal agencies located within their service areas. The three PMAs in our study market power in 30 states from 103 hydropower plants and a coal-fired power plant. Figure 2.1 shows the service areas for each PMA and appendix III lists the hydropower projects from which the PMAs market power. As described below, the PMAs differ in several ways, including the sizes of their service areas, the number of customers served, and the types of assets owned. In fiscal year 1994, Western marketed power to 637 customers in Arizona, California, Colorado, Nebraska, New Mexico, North Dakota, South Dakota, Utah, and parts of Iowa, Kansas, Minnesota, Montana, Nevada, Texas, and Wyoming. Western’s power is largely generated from 56 hydropower plants. They have an existing capacity of 9,808 megawatts (MW) operated mostly by the Bureau. Western owns 16,727 miles of transmission line. In fiscal year 1994, its revenues from power sales were about $658 million, based on about 36.1 billion kilowatt-hours (kWh) of energy sold. Although about 60 percent of Western’s sales are to municipalities, cooperatives, and public utility districts, about 6 percent of its sales are to irrigation districts (see table 2.1). Most of the remaining power sales are to state and federal agencies and investor-owned utilities (IOU). Southwestern, serving Arkansas, Kansas, Louisiana, Missouri, Oklahoma, and part of Texas, marketed power to 62 customers in fiscal year 1994.Southwestern’s power is generated from 24 hydropower plants operated by the Corps with an existing capacity of 2,051 MW. Southwestern’s revenues from power sales in fiscal year 1994 were about $98 million, based on sales of about 6.6 billion kWh. Over 95 percent of Southwestern’s sales are to municipal utilities and cooperatives (see table 2.1). Southwestern also owns 1,380 miles of transmission lines. Southeastern, serving Alabama, Georgia, Kentucky, Mississippi, South Carolina, Tennessee, Virginia, and West Virginia, as well as parts of Florida, Illinois, and North Carolina, sold power to 294 customers in fiscal year 1994. Southeastern’s power is generated from 23 hydropower plants operated by the Corps with an existing capacity of 3,092 MW. Southeastern’s revenues from power sales in fiscal year 1994 were about $156 million, based on sales of about 7.9 billion kWh. Southeastern sold 57 percent of its power to municipalities and cooperatives. The remainder went to federal agencies and public utility districts (see table 2.1). Because Southeastern owns no transmission lines, it relies upon other utilities for transmission services. While the preference customers of PMAs are publicly owned utilities and state and federal agencies that generally purchase small amounts of electricity, they vary greatly. The types of customers served by Southeastern, Southwestern, and Western vary both in terms of type and size. They include municipalities and cooperatives; public utility districts; irrigation districts; federal agencies, including military and laboratory installations; and state agencies. Some customers are utilities that are among the largest in the nation, while others are among the smallest. Some customers generate much of the electricity they transmit to their customers, while others only transmit electricity they buy from other sources. For all three PMAs, municipalities and cooperatives are by far the most prevalent customers, accounting together for about two-thirds of all customers. Public utility districts and irrigation districts together account for about 8 percent of customers, while federal agencies, including military and laboratory facilities, account for about 7 percent. State agencies account for about 5 percent of all customers and IOUs account for about 3 percent. Figure 2.2 depicts the composition of customers for each PMA. The PMAs’ preference customers also vary in size. As shown in fig. 2.3, about two-thirds (67 percent) of Western’s preference customers are small utilities. About 6 percent of Western’s preference customers are in the medium category and another 6 percent are large. About half (47 percent) of Southwestern’s preference customers are small utilities. However, almost one-third (30 percent) of Southwestern’s preference customers are large. In contrast, almost half (47 percent) of Southeastern’s preference customers are medium-sized utilities. The preference customers of the three PMAs also vary in terms of the quantity of electricity purchased. As shown in figure 2.4, although a few customers purchase large quantities of electricity from PMAs, most purchase smaller quantities. For example, in fiscal year 1994, about 83 percent of the preference customers purchased 50,000 MWh or less from the PMAs and over 90 percent purchased less than 100,000 MWh. The PMAs also sell to a few larger customers (about 1 percent of their customers each buy over 1,000,000 MWh). Most preference customers obtain the majority of their electricity from sources other than the PMAs. As shown in figure 2.5, about 75 percent of the PMAs’ preference customers purchase less than half of their total electricity from the PMAs. In addition, over 60 percent of the preference customers receive no more than 25 percent of their electricity from the PMAs. Because the PMAs have a limited quantity of power for sale that must be allocated among many preference customers, these customers must obtain most of their electricity from other sources. However, the PMAs differ in how much they provide as a percentage of their customers’ total needs for electricity. About 99 percent of Southeastern’s preference customers purchase no more than 25 percent of their electricity from the PMA. In contrast, Western supplies more than half of the electricity to over 40 percent of its preference customers. Southwestern, on the other hand, supplies no more than 25 percent of the electricity used by most of its preference customers. Yet, it also supplies over 20 percent of its preference customers with at least 75 percent of their electricity. PMA officials and representatives of preference customers maintain that the total portion of electricity the PMAs supply to them does not accurately portray the PMAs’ importance because the PMAs primarily provide power to them during periods of peak demand when electricity from other sources is in relatively short supply. Therefore, measuring the customers’ reliance on the PMAs in terms of their purchases of electric energy (measured in kWh) does not accurately capture the situation of some preference customers, particularly those of Southeastern and Southwestern, that rely more on the PMAs to meet their peak demands for electricity. These customers may use electricity from the PMAs more for meeting peak demands than for providing normal baseload electricity. In response, representatives of IOUs contend that most preference customers could purchase this electricity from other sources. In fiscal year 1994, the PMAs sold power at a wholesale rate that was about one-half of the wholesale rates offered by other utilities. For example, the combined average revenue earned per kWh sold by the three PMAs in our study was about 1.8 cents compared with a national rate of about 3.5 cents for IOUs and about 3.9 cents for publicly owned generating utilities (POG). In fiscal year 1994, Southeastern’s average revenue of about 2.0 cents per kWh compared with wholesale rates of about 4.2 cents per kWh for IOUs and about 5.3 cents for POGs in the region in which Southeastern serves power. In fiscal year 1994, Southwestern received average revenues of about 1.5 cents per kWh. In comparison, IOUs’ average revenues per kWh ranged from about 2.6 to 4.5 cents per kWh, while POGs’ average revenues per kWh ranged from 3.5 to 4.1 cents per kWh in the region in which Southwestern sells power. In fiscal year 1994, Western received average revenues of about 1.8 cents per kWh for its electricity. In contrast, IOUs received average revenues ranging from about 2.7 to 3.5 cents per kWh and POGs’ average revenue ranged from about 3.3 to 4.1 cents per kWh in the region in which Western sells power. According to a PMA official, because of the low rates PMAs offer, the PMAs have informal waiting lists of prospective preference customers that want to buy their power. Although Western is implementing a program to set aside some existing capacity to serve new customers, becoming a new PMA customer is difficult because few customers are willing to give up their power allocations from a PMA and almost no new federal hydropower plants will be coming on line in the foreseeable future. Many factors contribute to the PMAs’ ability to sell electricity at generally lower rates than other neighboring utilities. Importantly, their electricity is primarily generated from hydropower plants, making their power generally less expensive than other sources of power because it has no fuel cost. In addition, because most of these hydropower plants were built when construction costs were lower than more recent construction, the PMAs have lower imbedded costs to recover through their rates. Also, as we discussed in our 1996 report, their rates do not fully recover all of the costs associated with production of power. In some cases, the PMAs are not required to recover some costs (for example, certain environmental costs and the full costs of federal pensions and postretirement health benefits) because of specific legal provisions or because the DOE implementing order excludes the costs or is not specific about them. Also, unlike IOUs, the PMAs do not pay federal income taxes nor do they set their rates to earn a profit. In addition, while the PMAs in our study do not have to build new capacity to meet future demand, IOUs have an obligation to serve all existing and future customers in their service areas. Therefore, they must build new generating capacity and recover the associated capital costs through their rates. This requirement could result in higher rates for IOUs, depending on the cost to increase this capacity. The PMAs have a close working relationship with the Bureau and the Corps, which operate and control the hydropower plants and ensure that hydropower is generated subject to the other multiple purposes of federal water projects. These relationships are based on written documents and on flexible arrangements. The PMAs market power subject to the parameters of these written agreements and flexible arrangements. The flexible arrangements allow the operating agencies to balance a project’s multiple purposes, even if this reduces power production. For example, releasing water in the late summer to improve oxygen levels downstream to benefit fisheries reduces the capacity to generate electricity. In allocating water among a project’s multiple purposes, the Bureau and the Corps arbitrate among the competing purposes for water. The Bureau operates primarily in the West and manages water in federal water projects mostly for irrigation. The Corps manages water mostly for flood control and navigation. The Bureau and the Corps also provide water for fish and wildlife habitat enhancement, municipal and industrial supplies, recreation, and water quality improvement. How much electricity the PMAs can sell is subject to the Bureau’s and the Corps’ control of the water. How the Bureau and the Corps control the water, in turn, is affected not only by the multiple purposes of a project but by the interests of outside stakeholders. For instance, under provisions of the Clean Water Act, state agencies issue water quality certificates that affect how federal dams are operated and the amount and timing of water that can be released from a reservoir. Moreover, compacts to apportion water among states affect the availability of water for various purposes. The Bureau and the Corps must also frequently consider state environmental laws when managing water resources. For instance, in operating the Central Valley Project (CVP) in California, the Bureau follows a decision by the California State Water Resources Board that directs the CVP and the state water project to meet the state’s standards for fish habitat and water quality, such as the salinity standards for the San Francisco Bay area. To accomplish these standards, the Bureau and the management of the state water project operate under an agreement that describes how water supplies should be shared and who would be responsible for environmental issues. For example, under one aspect of this agreement, the Bureau would be responsible for about 75 percent of the fish and wildlife habitat and water quality responsibilities in some cases. The Bureau or the Corps and the PMAs interact when planning the management of a river system, so that releases of water, which are frequently accomplished through the generating turbines of a hydropower plant, can be timed to maximize the use of water for the sale of hydropower. Western and Bureau officials in Salt Lake City, Utah; Sacramento, California; and Billings, Montana; for example, explained that the Bureau prepares annual operating plans that are updated monthly. In January of each year, the Bureau completes the first surveys of mountain snow. By entering the resulting data into its model, the Bureau makes preliminary predictions about run-offs and annual hydrological conditions. Western, water users, environmentalists, and other stakeholders then meet to review the 12-month operating plan. The Bureau updates the plan monthly as new hydrologic information becomes available. For each month in a rolling 12-month period, the annual operating plan contains the following information by reservoir, dam, and hydropower plant: water inflows, water levels, projected water releases, projected water deliveries, and estimated power generation by each hydropower plant according to the maintenance schedule and planned outages. Based on information about hydrology, reservoir levels, and the demand for water, the Bureau issues daily water orders that fine tune water releases and water movements to accommodate the project’s multiple purposes. The staff of the Bureau’s control center and Western’s power dispatchers coordinate water releases so water is released through the turbines to maximize the value of the power generated within the parameters defined by the other multiple purposes of the project. The general process governments use to divest their assets is composed of many decisions. In reviewing domestic and international divestiture experiences, we found a successful divestiture begins with a definition of the sale’s objectives, which typically include (1) reducing or eliminating the government’s presence in an activity that some view as best left to the private sector and (2) improving the government’s fiscal situation. Both of these objectives have been advanced by those who favor the federal government’s divestiture of its hydropower assets. However, those who oppose divesting these assets argue that there are advantages stemming from the government’s current hydropower activities and question whether divesting the federal hydropower assets, including the PMAs, would actually improve the government’s fiscal position. Once a decision has been made to divest certain federal assets, the underlying objectives will shape the sales process. In particular, they will shape the general decisions about which specific assets are sold, what conditions and liabilities will transfer with those assets, and how to implement the sale. A successful divestiture of government assets generally starts with defining the objectives of a sale. Divestiture proposals have been motivated by two broad objectives, typically in conjunction with one another: (1) to reduce or eliminate the government’s presence in an industry that is viewed as best left to the private sector and (2) to improve the government’s fiscal position. International experience with divestitures suggests that one common objective for divesting government assets was a belief that certain functions being provided by the government would be more efficiently undertaken by the private sector. Some proponents believe this premise is true in the context of federal hydropower assets, because they believe the federal government should not be involved in generating, transmitting, and marketing electricity in wholesale markets. They maintain the following: The historical justification for the federal presence in the electricity industry—to provide electricity at the lowest practicable cost to regions that were too remote or sparsely populated to be served by investor-owned utilities (IOUs)—is outmoded. The entire nation has become electrified; new technologies, such as the gas-fired turbine, generate electricity at relatively low capital costs; and nonutility generators, such as independent power producers, now generate and sell power in wholesale electricity markets that have become increasingly competitive. In addition, the 1992 Energy Policy Act required that a utility make its transmission lines accessible to other utilities (called “open transmission access”), thus enabling customers to obtain electricity from a variety of competing utilities. As the market has become increasingly open, spot and futures markets in bulk power have grown and power marketers and brokers now offer services so wholesale customers can buy the cheapest power available. The tax advantages and other subsidies the PMAs receive give them unfair advantages over their competitors. As we recently reported, federal hydropower is cheaper than wholesale power sold by IOUs and publicly owned generating utilities, in part because hydropower has no fuel cost, but also because the PMAs have received low-interest financing and have flexible repayment terms.If federal hydropower assets are sold, the private sector would operate these assets more efficiently. Proponents believe that the federal agencies do not adequately operate, maintain, and repair these assets. As we recently testified, the government’s capital planning and budgeting systems do not enable federal agencies to fulfill these responsibilities adequately. Furthermore, according to proponents, the private sector would make better decisions about maintenance and investment because the decisions would be based on market signals rather than the federal government’s appropriations and budget cycles. In responding to a draft of our report, Corps officials pointed out that, in some instances, the Corps’ efforts to better operate, maintain, and repair its hydropower plants have paid off, and they cited that the Corps’ South Atlantic Division (Atlanta, Georgia) has improved the generating availability of its hydropower plants to over 90 percent for fiscal year 1996. PMA officials added that not all federal hydropower assets in all regions of the nation exhibit these problems. International experience also suggests that asset divestitures have been typically motivated by a desire to reduce the government’s debt or deficit. This can include reducing the size or activities of the government. Some policymakers propose selling the federal hydropower assets to improve the federal government’s fiscal position: They believe the cost of the federal hydropower program exceeds its value to the government because, among other reasons, the rates the PMAs charge do not recover all of the costs associated with generating, transmitting, and marketing electricity. If the government would sell these assets, the lump-sum payments would reduce the federal government’s current borrowing requirements. The government would also save money on the annual appropriations that would no longer be needed for the three PMAs and the operating agencies for operating, maintaining, and repairing those assets. While the U.S. Treasury would no longer receive annual revenues from the sale of federal hydropower, proponents of divestiture believe that the sales proceeds the federal government would receive from the divestiture and the reduced government expenditures would more than offset the forgone revenues from electricity sales. Some proponents also contend that a divestiture would eliminate any subsidies to PMA ratepayers. However, assessing the full financial impact on the government from a sale of hydropower assets requires that other indirect costs to the government also be considered. Furthermore, assessing the full financial impact requires examining a variety of revenue and expenditure components, expressing these in present value terms that reflect their timing as well as magnitude, and addressing underlying uncertainties through sensitivity analyses. For instance, the government would incur transactions costs—associated with preparing for and carrying out a divestiture—if it sells the assets. These costs could be significant, particularly in the case of a large-scale public stock offering. Additionally, a variety of labor costs, such as providing severance packages to terminated employees of the PMAs and/or operating agencies, and other costs associated with the disposition of their pension and postretirement benefits would need to be accounted for. Furthermore, a divestiture could create more regulatory responsibilities, and the costs of meeting those increased responsibilities would have to be considered a cost of the divestiture if those costs would not have been incurred otherwise and would be borne by the government. Proponents contend that some of these additional costs may be offset by the additional tax revenues the federal government would receive from sales of electricity if the PMAs and related hydropower assets were sold to IOUs or independent power producers. The Edison Electric Institute (the trade association of IOUs and a strong advocate of divesting federal hydropower assets) maintains that, if the three PMAs in our study were sold to private utilities, the present value of potential federal income taxes on purchasers and bond buyers could equal about $1 billion. However, these taxes may reduce how much a potential purchaser would offer for the PMAs by an amount approximately equal to the tax liabilities. Thus, counting the expected additional tax revenues without considering the offsetting effect on the expected sales price would overstate the financial benefits of the sale. Finally, it is important to note that the budgetary treatment of a sale of federal assets does not reflect the full, long-term financial impact of the sale on the Treasury. For example, current budget rules use a 5-year budget window for scoring government revenues and expenditures.Many observers believe that this period is not long enough to evaluate an asset sale in which lump-sum sales proceeds are compared to changes in expenditure and revenue streams that may continue for up to 50 years. In addition, without legislative change, the sales proceeds from a divestiture could not be used to finance new spending or offset revenue losses. Furthermore, the congressional committees that have jurisdiction over the entities being sold could not count the sales proceeds toward the deficit reduction goals specified under the Budget Enforcement Act of 1990, as amended. This means the committees could not use the proceeds to offset additional expenditures within their budget allocation. However, because the sales proceeds would flow directly to the Treasury, the proceeds would reduce the government’s overall borrowing requirements. Those who favor the government’s current role in providing hydropower maintain that the debate about divesting hydropower assets should also consider many other effects. They point to long-standing federal policies to use federal water projects to help develop local and regional economies and the importance of the revenue the government receives from the sale of hydropower. For example, as an “aid to irrigation,” power revenue is counted on to repay about 70 percent of the federal government’s (nominal) capital investment in irrigation facilities at federal water projects in the West. Parties that favor continued government ownership argue that the sale of federal hydropower promotes competition. They also assert that private-sector generation and marketing of hydropower formerly provided by the PMAs would lead to greater monopoly power in the electricity industry and higher rates to consumers, especially those in remote rural, low-income areas. In addition, the opponents of the sale believe that the PMAs’ electric rates are not subsidized and that, if the federal government sold its hydropower assets, the taxpayer would lose a steady stream of revenues that over time would exceed their selling price. Once a decision has been made to divest, then additional decisions would be needed to answer several broad questions. For instance, what specific assets would be divested? What associated conditions and liabilities would be transferred? And, what methods would be used to value and sell the assets? The final sales proceeds would depend on just what decisions would be made. As we found in our review of divestitures in other nations, an important, initial decision in a divestiture involves determining which assets to sell. In this regard, federal hydropower assets could be grouped in several different ways. First, a PMA itself could be sold, including any transmission assets and/or the right to sell the hydropower generated at the Bureau’s or the Corps’ hydropower plants. In a second alternative, a PMA, including its transmission assets and its right to sell power, as well as the Bureau’s or the Corps’ powerplants could be divested. In a third, more complicated alternative, a PMA and all of the aforementioned items as well as the remaining assets related to the water projects (e.g., the dams and the reservoirs) could be divested. An alternative to selling an entire PMA and any related hydropower assets could be to package the assets of a specific project for sale. For instance, Bureau officials in Sacramento, California, opined that the Central Valley Project could be sold to the state of California because the project is contained fully in that state and complements the existing water project that is managed by the state. Another option could be to sell all the federal hydropower plants on a river system together to preserve operating efficiencies because the releases of water from upstream facilities to downstream ones could be more easily coordinated under one-party ownership—an important consideration for flood control and other water management purposes. Along with defining the specific assets to be divested, policymakers would have to consider the explicit and implicit liabilities borne by the government and which of those liabilities to transfer to a buyer. As a policy matter, the government may want to retain certain liabilities associated with the assets being divested or place specific restrictions on their postdivestiture use of these assets. However, policymakers would need to consider that assets that are sold with many or relatively onerous restrictions (from the viewpoint of a prospective purchaser) or assets that are in poor condition are correspondingly less attractive and would likely result in lower sales proceeds than otherwise. While the government may still choose to place restrictions or to assign or retain certain liabilities, the financial consequences in terms of the sale price should be assessed. Many combinations of assets and liabilities could be grouped for sale. Both defining and valuing the specific liabilities that the federal government could retain are important because the government may be in a better position to bear certain risks. In general, the government could receive larger sales proceeds by retaining certain liabilities because a purchaser could substantially discount its bid if the purchaser would assume the financial risks associated with those liabilities. For instance, in the proposed divestiture of the United States Enrichment Corporation (USEC), the government would retain liability for the environmental cleanup associated with the prior production of enriched uranium. According to a contractor’s report, decontamination and decommissioning activities at uranium enrichment plants could cost as much as $17.4 billion in 1994 constant dollars. The PMAs are liable for environmental cleanup associated with use of polychlorinated biphenyls and other hazardous waste. While no precise estimates have been made, these liabilities could total many millions of dollars. Assets that are in better operating condition are more likely to receive larger bids than assets in poor condition. We testified recently that federal hydropower plants in the Southeast have experienced significant outages and that these outages occur because of the age of the plants and the way they have been operated. If these hydropower assets were to be sold without reducing the current backlog of necessary maintenance, bids would be lowered. However, a 1995 World Bank review of international experience with divestitures found that in preparing a government enterprise for divestiture, a government should generally refrain from making new investments to expand or improve that enterprise because any increase in sales proceeds is not likely to exceed the value of those investments. Imposing restrictions on operating the assets could also reduce the value to potential buyers. For instance, significant restrictions on using water to generate hydropower at the Glen Canyon Dam have been implemented to protect a variety of natural and cultural resources that are located downstream. According to the Bureau, these restrictions reduced the dam’s generating capacity by an amount exceeding 400 MW, even though total energy production over the course of a day or a season will be largely unchanged. It is almost certain that a new owner of the Glen Canyon Dam would continue to bear the responsibility to operate the dam’s hydropower plants according to these restrictions. As a practical matter, bids by prospective purchasers of the rights to market hydropower produced at Glen Canyon Dam would presumably reflect the diminished revenue potential. Thus, the government would incur much of the financial cost associated with the current restrictions in the form of reduced proceeds from the sales, just as the government would continue to bear this cost if its continued ownership and operation of the dam were maintained. Moreover, uncertainty about the extent of such restrictions likewise increases the uncertainty of expected future revenues and would likely reduce proceeds from the sale. In previous deliberations over divesting federal hydropower assets, including the PMAs, policymakers debated the desirability of ensuring regional control of divested federal hydropower assets. While a decision to limit bidders on particular assets to certain geographic areas would foster a goal of local or regional control of those assets, it could reduce the proceeds from the sale if other potentially interested buyers were precluded from making offers. For example, in the divestiture of the Alaska Power Administration—the only PMA to be offered for sale—an overriding concern was to protect the PMA’s ratepayers from possible increases in electricity rates. This concern led decisionmakers to restrict the eligibility of bidders to only ones from within the state. It also led decisionmakers to accept a sales price approximating the present value of future principal and interest payments that the Treasury would have received instead of establishing the price by selling the assets in an open, more competitive fashion to the highest bidder. The objectives underlying a divestiture help determine the most appropriate sales method. For example, if a divestiture were largely motivated by fiscal considerations—with an emphasis on sales proceeds—an appropriate sales mechanism would involve some form of competitive bidding and tend to place few restrictions on the number or identity of bidders. Alternatively, if the major motivation were a desire to transfer operations to the private sector—with an emphasis on a smooth transfer—the government could choose to negotiate a sales price with a selected buyer. In general, we have supported the principle that the federal government should seek the full market value in selling its assets. Sales methods that allow for competitive bidding are more likely to generate this result and lead to the transfer of assets to those buyers who value them most highly. A World Bank survey of international experiences with divestiture indicates that open bidding among competitors is preferable to sales that rely on negotiations with selected bidders because the former method offers less opportunity for favored buyers to receive special treatment at the taxpayers’ expense. In practice, the size of the assets to be sold, in terms of value and scale of enterprise, has influenced the type of sales process used. Trade sales and public stock offerings are general processes, with trade sales used more often to sell smaller enterprises or assets, and public offerings used to sell larger ones. Also, within each type, sales can be organized using competitive bidding methods or negotiations. A brief description of these processes follows: “Trade sales” draw on the idea that an existing set of businesses competing in the relevant line of business (or trade) are likely to offer more and higher bids for the assets. Three key attributes of the PMAs and the electricity industry may lend themselves to a trade sale: (1) The PMAs and related hydropower assets are part of an established industry with capital market connections experienced in the valuation, grouping, and sale of electricity-generating assets. (2) Sales of significant electricity-generating assets are not unusual. (3) There would likely be several bidders for at least large portions of the PMAs and their related assets, depending on how those assets are grouped for sale. A trade sale can be a negotiated sales process between the government and a buyer or can be accomplished using an auction to determine both the sales price of the asset or assets as well as the buyer or buyers. Stock offerings have been used domestically, most recently in the sale of Conrail in 1987, as well as internationally to divest large public enterprises. This method of sale would most likely require creating a government corporation or corporations out of the PMAs and their associated assets. Some of these assets could be grouped for sale, and some could be excluded from the sale, depending on the policy trade-offs discussed. In the case of some federal water projects, for example, the government could decide to retain control of the dam and reservoir to satisfy increasingly significant restrictions on the use of water because of concerns about the environment or endangered species. The stock of the government corporation would be subsequently sold through standard financial market methods, such as a private placement through negotiations between particular investors and the government or through a sale to the general public by using competitive bidding. In cases where auction methods might be selected to sell government assets, recent government experience indicates the importance of carefully choosing the specific format for an auction. That is, a policy decision to choose a competitive auction format requires making many subsequent decisions to define the specific rules leading to an appropriate operational auction. For example, the Federal Communications Commission has chosen to auction the leases of electromagnetic spectrum licenses for use in mobile communications. While generating a large amount of revenue was a less important goal than achieving an efficient geographic allocation of spectrum licenses to communications firms, the auctions generated more revenue than had been predicted by some potential bidders, according to auction analysts. In large part, the success of these auctions was due to careful consideration of the auction format and the identification of particular problematic features of auctions of similar assets in other countries. Most domestic and international divestitures have relied on private capital market firms as consultants and managers because of their frequent experience with complicated and high-valued transactions governing the transfer of assets in the private sector. Particularly in the case of public offerings but also for trade sales, the government would likely incur substantial costs to prepare its assets for sale or to pay for services performed by its financial advisers. For example, in the sale of Conrail, the government employed a variety of financial advisers and, in a key role, a prominent law firm with expertise in a variety of fields, including tax and employment law. Within the government, a variety of possible divestiture management options exist to guide the divestiture process and implement the decisions that must be made. In the Conrail divestiture, the Department of Transportation was primarily responsible for managing the sale. In the ongoing Alaska Power Administration sale, DOE is the lead agency. In our review of the USEC divestiture, we recommended that the Secretary of the Treasury lead the privatization process because that official will not be affected by the privatization and the Secretary’s mission is clearly defined in terms of protecting taxpayers’ general interests. Besides the general decisions that arise from any complex divestiture, many specific issues related to federal hydropower would need to be addressed before a divestiture of federal hydropower assets could be completed. These issues include the multiple purposes of federal water projects; the existing contractual obligations and liabilities of the PMAs, the Bureau, and the Corps; the future responsibility for environmental liabilities and protecting endangered species, which already constrain the operations of many projects; the rights and concerns of Native Americans; and the future regulatory treatment of the hydropower assets. The potential effects on wholesale and retail electric rates, including potential regional economic effects, would also need to be considered. Although determining how wholesale rates would be affected by a divestiture is difficult, the impacts would be influenced by the extent to which customers buy a large portion of their power from the PMAs and the prevailing wholesale rates in the regional market. The impact on retail rates and any regional economic impacts would depend on the extent to which a PMA’s customers would absorb any cost increases or pass them on to their retail customers. A divestiture of hydropower assets would require time and resources. However, complex issues have arisen and been successfully addressed in transfers of assets in the private sector. For example, for nonfederal facilities, balancing the multiple purposes of the water projects has been historically managed through FERC’s licensing process. In addition, when FERC decreased its regulation of the natural gas industry and the industry restructured itself, thousands of new contracts were negotiated and rewritten. The purposes and the management of federal water projects are guided by many statutes, including federal water management and reclamation statutes generally applicable to all projects, specific authorizing and appropriations statutes for individual projects, and environmental protection statutes. Many federal projects serve multiple purposes, such as fish and wildlife habitat protection, flood control, hydropower generation, irrigation, municipal and industrial water uses, navigation, recreation, and water quality improvements. Unless the legislation that authorized a divestiture exempted the water projects from these laws, the statutory provisions would continue to affect how the new owners would manage the projects and how much electricity the new owners could generate. See appendix II for a description of relevant federal statutes. As described in chapter 2, under current arrangements the Bureau and the Corps manage the allocation of water in federal water projects to balance their multiple purposes. The uses of the water are sometimes complementary and sometimes competitive with one other. For example, water is stored in and is released from the reservoir to provide for recreation, but its release through the turbines could be scheduled to generate electricity in a way that is intended to maximize revenues. In contrast, Western’s office in Billings, Montana, forecasts decreases in power revenues in the long-term because water, which would otherwise be used to generate electricity, will increasingly be used for irrigation and other purposes. In its fiscal year 1995 repayment study, Western predicted that revenues from the sale of hydropower could decrease from about $253 million in 2001 to about $213 million (in constant 1995 dollars) in fiscal year 2080 for the Pick-Sloan Program. Under authorizing legislation, such as the Flood Control Act of 1944 and the various reclamation acts, the Bureau and the Corps enjoy some latitude in managing water for various purposes. These agencies’ role in arbitrating between multiple uses becomes especially visible during times of drought. For example, according to Western officials, during the drought of the late 1980s and early 1990s, water was increasingly assigned to irrigation. As a result, power generation suffered significantly in Western’s service area. The role of the Bureau and the Corps has also become increasingly important as population and economic growth have intensified the competition over how water is used. For example, competition for water is now emerging even in areas with abundant rainfall, such as the Southeast. For several years, Alabama, Florida, and Georgia have been contesting the uses of water on two river basins in the Southeast (the Alabama-Coosa-Tallapoosa and the Apalachicola-Chattahoochee-Flint) that are managed by the Corps. Georgia, which contains the headwaters of the waterways in question, needs increased water supplies to provide for the growing population of the Atlanta area, as well as for farming and industry. Florida is concerned about the effects of water levels on its barging industries. It is also concerned about upstream pollution because water from the Chattahoochee and other rivers flows into Apalachicola Bay—a rich source of shellfish and shrimp. Alabama is also concerned about the cumulative impacts of potential water resource actions. In the 1980s, the Corps, responding to requests from several Georgia communities for additional water withdrawals from reservoirs, planned to reallocate water away from generating hydropower to increase the water supply. In June 1990, Alabama sued the Corps, challenging the adequacy of documentation about the environmental impacts of those reallocations and the Corps’ procedures for operating its reservoirs. However, in January 1992, after Alabama put aside the lawsuit, the governors of the three states signed an agreement with the Corps to work together through a study to resolve their issues. This study is projected to be completed in December 1997. The ability of the Bureau and the Corps to continue to balance the purposes of a water project after a divestiture would depend largely on the types of assets that were being sold. If only the PMA and its transmission assets were divested, then the Bureau and the Corps would continue to control how water is allocated, used, and released, because they would continue to own and operate the dams, the powerplants, and the reservoirs. According to Bureau, Corps, and PMA officials, the impact of such a divestiture on the operation of a water project and its multiple purposes would be manageable because the buyer would have to dispatch and market power subject to the Bureau’s and the Corps’ continued presence and decisions about water releases. However, the Bureau and the Corps would have to deal with a nonfederal entity with different incentives than the former PMA, which was a fellow government agency that understood the need to operate so as to meet multiple public purposes. If the PMA, its transmission assets, and the Bureau’s and the Corps’ hydropower plants were sold, then the Bureau and the Corps would retain ownership of the dams and the reservoirs and would continue to plan and manage the water. However, because water is released through both the spillways (which would continue under the Bureau’s or the Corps’ control) and the powerplant (which would be controlled by the nonfederal buyer), a nonfederal entity would have some measure of operational control over how and when water would be released. Bureau, Corps, and PMA officials explained that the operating agencies would have to be more vigilant than they have been when dealing with the buyer of the PMA and the powerplants. If the PMA, its transmission assets, the powerplants, the dams, and the reservoirs were sold, the Bureau and the Corps would no longer be responsible for managing how water is used and balancing the projects’ multiple purposes. As discussed later in this chapter, in this case a regulatory agency, such as FERC, would have to consider the projects’ purposes when licensing and regulating postdivestiture hydropower production and other activities at a divested project. FERC officials noted that nonfederal water projects licensed by the commission also have multiple purposes that must be accommodated. The irrigation function at federal water projects presents issues for divestitures that differ from the other project purposes. Specifically, as of September 30, 1995, power revenues were scheduled to pay for about $1.5 billion to recoup the federal capital investment for completed federal irrigation facilities. This amount is to be repaid for periods of up to 60 years for individual irrigation projects. Under current repayment practices, this debt is to be repaid without interest, and repayment of the debt can be deferred until the end of the repayment period. Moreover, according to the Bureau’s officials, because capital expenditures on irrigation facilities are expected to continue to increase for renovating and replacing existing facilities as well as constructing new ones, the total amount of “irrigation assistance” could also increase over time. However, most planned irrigation projects likely will not be completed because they are infeasible and not cost-effective. If Western, the related federal water projects, or irrigation projects within Western’s service area were sold to nonfederal entities, the issue of how this federal investment in irrigation would be repaid would have to be addressed. Hydropower is used at some federal projects within Western’s service area to power the pumps that move water from the reservoirs and the canals to the fields. In recent years, as much as about 30 percent of all electricity generated by the Bureau’s hydropower plants in California’s Central Valley Project (CVP) has been used for this “project pumping.” Moreover, at some federal irrigation projects, the rate that has been charged for “project pumping” electricity has been far below the rate that has been charged for commercial uses. According to Bureau officials, at the Eastern Division of the Pick-Sloan Program, the average rate per kWh sold in fiscal year 1995 was about 1.5 cents per kWh, while the rate for project pumping was only about 0.2 cents per kWh. Any divestiture would need to clarify whether the new owners would be required to provide power for irrigation below the rates paid by other customers. If the dams and the reservoirs were sold, then the government would have to negotiate arrangements to accommodate the use of water for irrigation. As agencies of the federal government, the PMAs, the Bureau, and the Corps have entered into a wide range of legally binding contracts in conducting the generation, transmission, and marketing of hydropower. Until the specific terms of a divestiture proposal and the accompanying legislation are known, identifying possible complications that could delay or otherwise affect the sale will be difficult. However, even if the legislation establishes the transferability of these contractual obligations, stakeholders might be able to delay or complicate the divestiture process by filing lawsuits. Although we did not review the thousands of contracts and other agreements that could be affected by a divestiture, according to Bureau and PMA officials, some of the government’s current contracts do not address the transfer of the government’s contractual obligations after a divestiture. Historical precedence exists in the energy sector for addressing extensive and complex contractual obligations. For example, after FERC ordered the restructuring of the natural gas industry, thousands of new contracts were written. FERC Order 636, which was issued in 1992, required, among other things, that all interstate pipeline companies restructure their tariffs, services, rates, and contracts and separate or “unbundle” their gas transportation and storage arrangements. To conform to this order, gas pipeline companies negotiated about 3,800 new contracts with their customers. One of the PMAs’ most important contractual obligations is selling power to their “preference customers.” The PMAs market hydropower on a wholesale basis at the lowest possible rates, consistent with sound business practices. The three PMAs in our study have contracts to sell power to over 990 customers at cost-of-service rates ranging from about 1.5 cents to about 2.0 cents per kWh. Although these rates may increase in the future, they are significantly lower than the average national wholesale rates of 3.4 cents per kWh for IOUs and about 4.0 cents for publicly owned generating utilities. Currently, the PMAs are renewing their power contracts. Western has extended its contracts in the Pick-Sloan Program through 2020 and is proposing 20-year extensions of power contracts at other projects. According to PMA officials, it is unclear whether a buyer of a PMA would have to continue selling power at low rates to preference customers and, if so, for how long. If a PMA were divested, its contractual obligations with its customers could be assigned in whole or in part to the buyer. In addition to power contracts, the PMAs have entered into interconnection, transmission, and right-of-way contracts and agreements that make them a vital part of regional power grids. For example, in addition to power contracts with 83 customers, Western’s office in Folsom, California, has numerous contracts and agreements for providing transmission and interconnection services, for buying power from utilities in the Pacific Northwest, for delivering power to irrigation projects via the transmission grid of another utility, and for acquiring rights-of-way and easements along transmission lines. Western has a key contract with the Pacific Gas and Electric Company (PG&E), first signed in 1967, that integrates the operations of the PMA and the company. Under this complex contract, Western provides peaking capability to PG&E in exchange for firm power services; PG&E also delivers 880 MW to Western’s preference customers. Moreover, to bring more power to its system, Western also owns part of the Pacific Northwest-Southwest Intertie and an interest in the California-Oregon Transmission Project, which allows Western to transmit power from the Bonneville Power Administration, Pacific Corp, and other utilities in the Pacific Northwest. Although Southeastern has no transmission assets, it has 17 contracts with regional utilities (including regional IOUs, state public power agencies, and electric cooperatives) to transmit power that is generated by hydropower plants the Corps operates. These contracts differ in the services provided, cancellation provisions, and customers served. Seven of the utilities, including the Tennessee Valley Authority (TVA), provide both transmission and ancillary services. These contracts are described in appendix IV. Because of the number and complexity of their contracts and agreements, the Bureau and the Corps were unable to provide us with information related to every contract and agreement they have implemented at the offices we visited. However, Bureau and Corps officials provided us with information to illustrate the number and types of contracts and other agreements that would have to be assigned or terminated if a project’s dam and/or reservoir were divested. For instance, in Southeastern’s service area, the Corps has over 5,100 agreements for such things as easements for roads and utilities; leases for public parks, agriculture, and concessions; and licenses for fish and wildlife management. See appendix IV for a description of these contracts and agreements. Likewise, the Bureau’s Great Plains Region in Billings, Montana, has over 2,200 contracts and agreements, which include the Bureau’s 580 right-of-use permits for such things as agricultural leases and permits concerning buffers, buildings, crops, drainage, and weed control. See appendix V for a description of these contracts and agreements. According to FERC officials, concerns about environmental impacts have begun to affect the generation of hydropower. The uncertainties about the federal government’s future responsibilities in funding and implementing actions to mitigate environmental impacts would greatly affect the divestiture of any hydropower assets. Other types of generating capacity, including coal-fired and nuclear powerplants, have also faced environmental and related constraints that have required costly mitigations. The desire to mitigate any potential negative effects of water projects on the environment, especially on the habitat of endangered and threatened species, is increasingly constraining the ability of the Bureau and the Corps, as well as nonfederal entities, to generate hydropower, especially during hours of peak demand. Because of these restrictions, the PMAs have forgone power revenues of millions of dollars since the late 1980s. In an example affecting Southeastern, the South Carolina Department of Wildlife and Marine Resources sued the Corps in 1988, alleging violations of the National Environmental Policy Act of 1969 at the Richard B. Russell Dam. The Russell project has eight hydropower units with a combined capacity of 600 MW—four conventional hydropower units (the last of which came into commercial operation in 1986) and four pumpback units (which have never been in commercial operation). The U.S. District Court for the District of South Carolina found that the Corps had violated the National Environmental Policy Act by failing to complete an environmental impact statement (EIS) and issued an injunction against the installation and operation of the pumpback units. However, the Court of Appeals for the Fourth Circuit partially reversed the district court and allowed the Corps to install the pumpback units but not operate them until another EIS had been completed. This supplemental EIS was completed and a settlement agreement was negotiated that allowed environmental testing. According to Southeastern, the PMA has lost power revenues of about $36.1 million per year since 1994 because of the shutdown. In another example that affects Western, the obligation to protect endangered species has had a significant impact on the CVP’s operations. Bureau officials said that, in response to the Endangered Species Act, the U.S. Fish and Wildlife Service listed the winter run of the Chinook salmon as endangered. According to these officials, to protect the needs of the salmon, the Bureau has restricted the use of the five hydropower units at the CVP’s Shasta powerplant. They added that since 1987 these restrictions have resulted in additional costs of about $50 million to purchase power to meet Western’s contractual obligations. According to officials from the Bureau, FERC, and the PMAs, as well as from environmentalist groups and trade associations, environmental restrictions on water usage to generate power will likely continue in the future. The effects will continue to include lost power revenues or, conversely, increased costs to procure alternative power supplies. For example, waterflow restrictions that are included under the preferred alternative of the final EIS of the Glen Canyon Dam could result in lost generating capacity of 442 MW in the winter and 470 MW in the summer. According to the Bureau, the cost to replace the lost capacity is about $44.2 million per year. The preferred alternative, also known as the “modified low fluctuating flow” alternative, features river flows that are substantially reduced from historic levels, including flows that vary for purposes of maintaining the habitat. The benefit of these modifications in managing water use include enhanced fish habitat and protection of endangered or listed species. Defining who would be responsible for mitigating the environmental impacts associated with federal water projects after a divestiture is a crucial issue that would have to be addressed when policymakers define the terms and conditions of the transaction. If only the PMA (including the transmission assets) and/or the federal powerplants were divested, then the government’s responsibilities would generally remain the same, unless specified otherwise in the divestiture legislation. If the government were to sell the dams and reservoirs, however, the responsibilities and costs of actions to mitigate environmental impacts would need to be allocated or reassigned. Moreover, with new and more comprehensive actions to mitigate environmental impacts, the uncertainty surrounding the availability of power would also need to be addressed. These actions frequently entail restrictions on releases of water to generate electricity or potentially significant, but unknown, future costs to mitigate environmental impacts. If the PMA and/or powerplants were divested, then uncertainty about the amount of power available for marketing could lower the price that buyers would be willing to pay or discourage some potential buyers from submitting bids. Likewise, if the dams and the reservoirs were divested, uncertainty about the amount of power that could be generated as well as uncertainty over the costs of future environmental mitigations could likewise lower the bids or discourage some prospective buyers from bidding. In addition, the existence of more competitive electric markets would also affect the attractiveness of purchasing the federal hydropower assets. Alternatively, if the government assumes some of the future liability for the costs of actions to mitigate environmental impacts, taxpayers may be forced to bear a significant, but currently unknown, future liability. Moreover, according to officials of DOE’s PMA liaison office, because environmental laws could require an EIS, testing, and cleanup when federal property is sold, additional costs to sell the federal hydropower assets could be incurred. In addition, PMA and Bureau officials stated that, in some cases, actions to mitigate environmental impacts are ongoing and would have to be considered in a divestiture of certain federal hydropower facilities. Various rights and concerns of Native Americans would have to be addressed in a proposal to divest federal hydropower assets. These issues include (1) their water rights, (2) their claims to surplus federal property, (3) the need to address rights-of-way for PMA transmission lines across their lands, and (4) the government’s responsibilities under the Native American Graves Protection and Repatriation Act to safeguard their cultural artifacts. In addition, according to Western officials, the PMA is reserving some of its capacity for Native American tribal entities that are expected to become new preference customers. The rights of Native Americans to water must be considered in a divestiture. Several Native American tribal entities hold reserved water rights with senior priority dates (for example, from time immemorial or the 1850s or 1860s) on river systems with federal water projects. Many of these entities have reserved water rights that have yet to be quantified and have water uses that have yet to be determined. The amounts of water associated with these rights and the manner in which the rights are exercised would likely affect hydropower operations and the distribution of power revenues. For example, according to Bureau officials, one legal settlement with tribes of the Fort Peck Reservation, Montana, included rights to about 1 million acre-feet of water from the Missouri River. Other potential claims of Native Americans would affect a divestiture of PMAs and related hydropower assets. For example, under federal legislation, excess federal real property in Oklahoma is subject to transfer to the Secretary of the Interior in trust for Oklahoma Native American tribal entities. According to Southwestern officials, this legislation would complicate a divestiture, although the extent of potential claims by Native Americans under this legislation is difficult to determine because of the lack of information about the prior ownership of lands on which the federal assets are located. According to PMA officials, the PMAs have 880 miles of transmission lines located on rights-of-way that traverse the lands of Native American tribal entities. In the event of a divestiture of a PMA’s transmission assets, if the Native Americans agreed to a transfer of these rights-of-way to a buyer, they could expect compensation. Finally, under the Native American Graves Protection and Repatriation Act, certain Native American cultural artifacts found on federal locations must be returned to the relevant Native American tribal entity. Corps officials responsible for managing federal water projects from which Southwestern markets power explained that they have been involved in numerous cases in the past several years involving this law. Providing federal hydropower to Native Americans would also affect a divestiture. According to Bureau and Western officials, in part because the federal government has a trust responsibility with Native American tribal entities and because those entities are expected to become new preference customers, Western is entering into a process to reallocate the power it will sell to its current and future customers. For example, it is setting aside at least 4 percent of its existing hydropower capacity at the Pick-Sloan Program for Native Americans and other new customers. Western is also changing its rules concerning power reallocations to make it easier for Native American tribal entities to buy federal power. These obligations would complicate a divestiture because they would involve selling power to new preference customers and extending existing contracts—for example, for 20 years (until the year 2020) at the Pick-Sloan Program. Before a sale could be completed, the regulatory treatment of the divested hydropower assets would need to be addressed. While many options for regulating the operations of divested hydropower assets exist, including regulatory regimes that could be established by federal, state, or regional authorities, FERC currently licenses the operation of nonfederal hydropower assets. With the proper resources, FERC officials believe they could license and regulate divested hydropower assets. They stated that the Bureau and the Corps have been able to accommodate emerging issues at federal water projects, such as environmental restrictions on water uses, with more flexibility than FERC’s quasi-judicial licensing process. They also stated that the Commission’s limited flexibility and the timing of its actions on licensing stem from the authority of other federal and state agencies to attach conditions to the license. Currently, FERC primarily regulates the reasonableness of wholesale rates charged by the PMAs and does not provide more detailed oversight of them and the Bureau’s and the Corps’ assets and operations. According to FERC officials, the extent of its regulation after a divestiture would depend upon the specific assets divested. A FERC operating license would not be needed if only the PMA’s assets (its right to market hydropower and, in the case of Southwestern and Western, also the transmission facilities) were divested because the operating agencies would continue to own and operate the powerplants. The operating agencies would continue to manage the water as in the past and the existing restrictions would likely remain in effect. The buyer would market the power subject to the same conditions as the former PMA—subject to the existing purposes of the water project. If a divestiture included the powerplants, the new owner would then be required to obtain a FERC operating license, unless the requirement for FERC’s licensing and regulatory activities were specifically exempted by legislation. Licensing a divested hydropower plant could take a long time; FERC’s licensing process averages 2.5 years but it has taken as long as 10 to 15 years. In granting an operating license for a hydropower plant, FERC is required to weigh the plant’s impact on such “nondevelopmental values” as the environment and recreation. The licensing action involves such numerous studies as the powerplant’s impact on fish, plant, and wildlife species; water use and quality; and any nearby cultural and archeological resources. Moreover, the government of each affected state would perform a water quality certification. In addition, to accommodate any “nondevelopmental values,” FERC could restrict the use of water for generating electricity, resulting in hydropower generating units that have been “derated”—that is, their generating capacity has been reduced. For example, according to studies by the Electric Power Research Institute,from 1984 to 1989, 16 hydropower plants that had been relicensed were actually derated while 8 powerplants increased their capacity. FERC officials cautioned that if the powerplant, dam, and reservoir were sold, then FERC’s licensing process could revisit the management and uses of the water and possibly change the available electric-generating capacity. The uncertainty regarding the length of time to complete FERC’s licensing process as well as the amount of generating capacity after licensing is completed could reduce the number and amounts of bids for the resources. However, if the new owners of a hydropower plant were allowed to operate the plant without a FERC license, they would have a competitive advantage against other operators who are subject to FERC’s licensing requirements. A congressional bill introduced on July 23, 1996, contained provisions that would have provided an operating license with a 10-year term for divested hydropower assets. The owners would then have been subject to a FERC license. In congressional testimony in 1995 regarding divestiture of the PMAs, the Chair of the FERC suggested that divestiture legislation specify an automatic grant of the 10-year operating license and require that the divested powerplants continue to operate according to the preexisting operating agreements. Following a divestiture, FERC would then subject the facility to the normal FERC licensing procedure. According to FERC officials, FERC would be able to regulate divested multipurpose federal hydropower assets because the Commission already has this responsibility for 1,000 nonfederal hydropower facilities. They said that most nonfederal hydropower plants have widespread impacts and multiple uses because their associated dams and reservoirs store water, thereby affecting water upstream, downstream, and across state lines. However, to handle numerous divestitures or complicated divestitures of federal hydropower assets, FERC would need to request congressional authority to add new personnel and resources. Precisely determining how the sale of the PMAs would affect the rates charged to customers is difficult. Some of the PMAs’ customers have expressed concerns that a divestiture of the PMAs could lead to significant rate increases, while some industry analysts have contended that rate increases would be small for most customers. However, some analysts believe that certain customers would be more likely to see larger rate increases than others. These customers are those who currently (1) buy a higher percentage of their total power from a PMA than others do, (2) pay rates for a PMA’s power that are significantly lower than the market rates in the region in which the PMA sells power, and (3) have few or no alternatives for buying power elsewhere at relatively low rates. According to PMA and industry officials, many of these customers are smaller ones located in geographically remote areas. Other factors, such as increasing competition in the wholesale market or mandated limits on rate increases could mitigate the rate increases for these customers. The change in retail rates to end-users (i.e., residential, industrial, and commercial customers) would depend on how much rates increase for the preference customers that serve them. However, the extent to which preference customers pass these increases on to end-users could be affected or mitigated by such things as their ability to increase operating efficiency. According to some industry analysts, preference customers who buy a higher percentage of their power from the PMAs would be more likely to experience greater postdivestiture rate increases than those who buy a lower percentage. (Most PMA preference customers buy power from the PMA as well as from other sources, as shown in ch. 2.) For example, if a customer buys 90 percent of its power from the PMA and the buyer of that PMA increases the former PMA’s rates by 50 percent, the preference customer would see its overall rate for power from all sources increase by about 41 percent, if all other factors were held constant. In contrast, if a preference customer buys only 10 percent of its power from the PMA, it would see its overall rate for wholesale power from all sources increase by about 3 percent. Because preference customers differ in how much they use the PMAs for their power, they will not be affected equally by a divestiture. As we mentioned in chapter 2, almost all (99 percent) of Southeastern’s customers purchase less than one-quarter of their total power from that PMA. In contrast, Western provides over 40 percent of its preference customers with more than half of their power. Therefore, if other factors would remain constant, we expect that Western’s customers would generally experience larger average rate increases than customers served by Southeastern. Some industry analysts believe that, after a divestiture, the buyer of a PMA would charge rates that conform to the prevailing market rate for wholesale power in the geographic region in which the PMA sells power.As discussed in chapter 2, these prevailing market rates are now significantly more than the rates the PMAs charge their customers. Thus, the difference between what a PMA currently charges its customers and the regional market rate could determine how much a buyer would increase its rates after its sale. The lower the PMA’s current rate (relative to the existing market rate), the greater the rate increase would be. However, the differences between a PMA’s rates and market rates for wholesale power vary across a PMA’s service area. For example, according to our previously cited September 1996 report, the difference between the average wholesale market rates of IOUs and Southwestern’s rates vary across its service area. In one part of Southwestern’s service area, its rates were 1.18 cents per kWh less than the average wholesale rates of IOUs, while in another part of Southwestern’s service area, its rates were 3 cents per kWh less than the average wholesale rates of IOUs. As a result, preference customers in different regions would experience different rate increases in the event of a divestiture. Those geographically remote preference customers that would not have access to many alternate suppliers of electricity after a divestiture would be the most susceptible to rate increases that would exceed competitive market rates. Conversely, if a preference customer could purchase power at competitive rates from other sources, the buyer of a PMA would be less likely to raise its rates. Representatives of the Edison Electric Institute maintain that because the wholesale market is competitive, very few preference customers will lack access to alternate suppliers following a divestiture. They believe that, after a PMA is divested, preference customers who relied heavily on that PMA will be able to buy power from independent power producers, energy brokers, or energy marketers at a relatively low cost. In addition, they contend that many municipal and cooperative utilities already are competitive participants in the wholesale market. However, representatives of PMAs and their preference customers believe that having access to alternate supplies of electricity is not enough. They note that even in cases where preference customers may buy most of their electricity from alternate sources, these customers often rely on the PMA for power during hours of peak demand, particularly in regions in which Southeastern and Southwestern sell power. Having access to inexpensive power during times of peak demand is important to these customers because typically power sold to meet this demand is more expensive than power sold at other times. Finally, the ongoing deregulation and restructuring of the electric utility industry contributes to the difficulty of assessing the potential impacts of a divestiture. Wholesale electric markets are becoming increasingly competitive, offering preference customers and other utilities the opportunity to buy from more than one supplier of wholesale power. This trend creates additional uncertainty about any potential rate impacts from a divestiture. Following a divestiture, the retail rates paid by residential, commercial, and industrial consumers would reflect the changes in rates experienced by the preference customers who serve them. For example, retail customers served by preference customers who buy most of their power from the PMA may see significantly higher rate increases than retail customers who buy their power from preference customers that buy a smaller percentage of their total power from the divested PMA. However, in many cases, determining how preference customers would change the retail rates after a sale of federal hydropower assets would be difficult. For example, in competitive markets, some preference customers may be able to avoid passing on increased costs to their retail customers by increasing their operational efficiency. Alternatively, preference customers may choose to reallocate these rate increases from one customer class to another—for example, from industrial end-users to residential end-users—to keep operating costs low at industrial facilities. The degree to which a regional economy would be affected by the divestiture of a PMA would depend mostly on several factors—the regional economy’s reliance on that PMA’s power, the amount of change in overall retail electric rates, the importance of electricity in the regional economy, and the extent to which water allocations from the former federal water projects would be changed. Limited available studies have shown the economic impacts of a rate change by the PMAs to be minor on industrial and residential customers because preference customers have relied on power from PMAs for only a small portion of their total power and electricity has been a relatively small portion of the cost of doing business for most commercial enterprises and industries as well as a small portion of household expenditures. But regional economies that rely on such electricity-intensive industries as primary metals and chemicals would see the greatest amount of economic harm from any rate increases after a divestiture. According to officials of the Electricity Consumers Resource Council (ELCON), the cost of electricity for such industries as aluminum smelters, glass, and chemicals can reach from 30 percent to 40 percent of production costs. For example, in response to TVA’s double-digit rate increases of the 1970s, industries in its service area ceased their operations and in some cases relocated to where electrical rates were lower. TVA’s annual sales to industrial customers declined from about 25 billion kWh in 1979 to 16 billion kWh in 1993. Regional economies that rely heavily on water and water-dependent industries (e.g., in which farming relies extensively on irrigation) would also be affected by changes in water allocations after a divestiture. Depending on the terms of the preexisting contracts and the divestiture legislation, if the dam and reservoir were divested, then the purposes served by the federal water projects and associated water allocations could change. For example, FERC’s operating license could include, subject to existing laws, a condition that more water be used for environmental purposes and less for hydropower.

Summary: Pursuant to a congressional request, GAO provided information on: (1) profiles of three power marketing administrations, including their similarities and differences and how they interact with the agencies that operate federal water projects; (2) general parameters of the process by which federally owned assets can be sold; and (3) factors that would have to be addressed in a divestiture of federal hydroelectric assets, such as the relationship between power generation and the other purposes of federal water projects. GAO noted that: (1) the Southeastern, Southwestern, and Western Power Administrations all market the hydropower generated at federal water projects, but they serve different geographical areas and have different assets; (2) their customers vary in size and in their electric energy purchases; (3) PMAs are not the main source of electricity for most of their customers--in total the three PMAs in GAO's report supply about 7 percent of the electricity requirements of their customers; (4) the PMAs have a close working relationship with the Bureau of Reclamation and the Army Corps of Engineers--these interactions are based in part on written agreements and on flexible arrangements that recognize the operating agencies' role in managing water releases in a way that balances a project's multiple purposes. GAO also noted that: (1) two principal objectives have typically been cited by other nations and by the United States for selling government assets: (a) eliminating or reducing the government's presence in an activity that some view as best done by the private sector; and (b) improving the government's fiscal situation; and (2) these two objectives will affect many subsequent decisions needed to implement a sale, including: decisions about such concerns as what specific assets to sell, how to group these assets, what conditions and liabilities to transfer to the buyer, and what sales mechanism to employ. Finally, if, based on a broad policy evaluation of the pros and cons of privatization, a decision to divest federal hydropower assets is reached, several key issues specifically related to hydropower would need to be addressed, including: (1) balancing how water is used among the multiple purposes of federal water projects; (2) determining how to repay or otherwise address the federal capital investment in irrigation facilities of the affected projects; (3) assigning the numerous contractual obligations and liabilities of the Bureau, the Corps, and the PMAs; (4) handling Native Americans' claims to water, property and tribal artifacts; (5) determining the future responsibility for protecting the environment and endangered species--a commitment that already constrains the operations of many projects; (6) deciding the future regulatory treatment of divested hydropower assets; (7) the potential effects of a divestiture on wholesale and retail electric rates, and the regional economies; and (8) these impacts, to a large degree, would be determined by the prevailing wholesale electric rates of the local utilities in the region in which power from the PMA is sold, the region's reliance on this power, and the availability of other sources of power.