Federal Power: Options for Selected Power Marketing Administrations' Role in a Changing Electricity Industry
Released: 1998-04-06T00:00:00

Letter

Introduction

The electricity industry has been predominantly monopolistic and noncompetitive. Utilities (primarily investor-owned utilities—IOU) build power plants and power lines to provide all of the electricity needed by all existing and future customers in their exclusive service areas. Regulators in the states allow utilities to charge electricity rates that give them a regulated, specified level of return on these investments.

IOUs were initially reluctant to provide electricity to rural areas, mostly because the sparse population made it difficult for them to recover their costs and to earn a profit. The federal government has played an important role in the traditional market by selling power to rural America. The Department of the Interior’s Bureau of Reclamation (the Bureau) and the Department of the Army’s Corps of Engineers (the Corps) generate electricity at hydropower plants located at major federal water projects. The Department of Energy’s (DOE) power marketing administrations (PMA) generally sell this power in wholesale markets, mostly to publicly and cooperatively owned utilities that, in turn, sell power to end-use (retail) consumers. The PMAs repay the federal investment in the government’s power plants, power lines, and related assets through the revenues they earn by selling power. The Tennessee Valley Authority (TVA), a federal corporation, generates and markets power throughout Tennessee and parts of six other southeastern states. Moreover, the Department of Agriculture’s Rural Utilities Service (RUS) makes and guarantees loans to rural utilities to finance the construction and development of electric power systems. Although critics question the federal government’s role in providing power or in financing improvements to rural utility systems as markets restructure, the activities continue.

However, the traditional structure of the electricity industry has begun to change. Legislation and new generating technologies have introduced increased competition into the market, changing the environment in which the PMAs must operate successfully if they are to repay the federal investment in the power program.

Structure of the Electric Power Industry

Federal and state agencies regulate the activities of electric utilities. Traditionally, electricity service was viewed as a “natural monopoly”: A central source of power was seen as the most efficient way of generating, transmitting, and distributing electricity at a reasonable cost. Under the traditional regulatory compact between electric utilities and their state regulators, electric utilities were guaranteed monopolies within their exclusive service areas and regulated rates of return on their capital investments. In return, these utilities built generating and other facilities to provide all of the electricity needed by all current and future customers in their service areas. Under traditional “cost-of-service” regulation, electricity rates approved by state regulators reflected the utilities’ costs of building new generating plants and operating the power system. As shown in table 1.1, IOUs dominate the electricity markets: Although they account for only about 8 percent of the nation’s almost 3,200 electric utilities, they have over 75 percent of utility sales to ultimate customers and over 77 percent of total utility power generation. Most IOUs sell power at retail rates to several different classes of consumers and at wholesale rates to other utilities, including other IOUs; federal, state, and local government utilities; public utility districts; and rural electric cooperatives.

The traditional regulatory role of the federal and state governments was established under the Constitution and developed by federal law. Specifically, the Federal Power Act (formerly the Federal Water Power Act), which was enacted in 1920, and the Public Utility Holding Company Act established a regime of regulating electric utilities that gave specific and separate powers to the states and the federal government. State regulatory commissions (generally called “public utility” or “public service commissions”) regulate utilities’ activities within state boundaries, including the setting of wholesale and retail electric rates. At the federal level, the Securities and Exchange Commission regulates interstate electric utility holding companies by requiring them to register and divest holdings so that each company becomes a single consolidated system serving a specific geographic area. In addition, the Commission regulates how the holding companies issue and acquire securities. Under the Federal Power Act, the Federal Energy Regulatory Commission (FERC), formerly the Federal Power Commission, regulates interstate aspects of the electric utility industry, including financial transactions, wholesale rates, and interconnection and transmission arrangements.

In addition to IOUs, 932 customer-owned rural electric cooperatives and 2,014 publicly owned utilities provided power in 1996. Most rural electric cooperatives, usually formed and owned by residents of rural areas, distribute electricity only to their members. Operating throughout the nation except for Connecticut, Hawaii, and Rhode Island, cooperatives constituted 29 percent of all the nation’s electric utilities in 1996. Publicly owned electric utilities are nonprofit state and local government agencies, such as municipal utilities, state authorities, public power districts, and irrigation districts. DOE views publicly owned power as providing competition for IOUs and as charging power rates against which the power rates of IOUs can be compared. In 1996, almost 63 percent of all electric utilities in the nation were publicly owned utilities. Cooperatives and publicly owned utilities buy power from wholesale providers for sale to retail customers. However, some cooperatives and publicly owned utilities also generate their own power and transmit it to other utilities or distribute it to their own retail customers. The generation and share of the national energy supply for these types of utilities are provided in table 1.1.

The Role of the Federal Government in Traditional Electricity Markets

The federal government has played a significant role in the development of electricity markets. Because it was too expensive for IOUs to serve rural areas, federal power agencies provided power to those areas. In addition, the government provided financing to rural utilities to assist them in building and maintaining electricity distribution systems that provide electricity to rural users. In 1996, federal utilities provided almost one-tenth of the nation’s power. As a result of these activities, the federal agencies that generate and/or market electricity and that make or guarantee loans to finance improvements to rural electric systems had incurred a debt of over $84 billion as of September 30, 1996. This debt, it should be noted, can be classified as direct and indirect. The direct debt, totaling over $53 billion, is owed directly to the federal government—for example, RUS’ borrowers owe about $32 billion. The indirect debt, over $31 billion, is owed by the federal agencies to nonfederal parties—for example, TVA owed about $24 billion to nonfederal bondholders.

Federal Agencies Generate and Market Electricity

Federal entities that generate and/or market electricity—primarily the Bureau, the Corps, the PMAs, and TVA—provided about 10 percent of the nation’s electricity supply in 1996. The Bureau and the Corps generate hydropower at about 130 federally owned power plants located at federal water projects. Because these projects are managed for multiple purposes (for example, providing water for irrigation, water supplies, navigation, flood control, and recreation), the amount of power generated and marketed is affected by the availability and use of water for these other purposes.

Power generated by the Bureau and the Corps is marketed by four of DOE’s five PMAs: the Bonneville Power Administration (Bonneville), plus the three that are the focus of this report: the Southeastern Power Administration (Southeastern), the Southwestern Power Administration (Southwestern), and the Western Area Power Administration (Western). The fifth PMA, the Alaska Power Administration, differs from the others in that it operates its own power plants and distributes power directly to end-use (retail) customers. The PMAs in 1996 provided about 5 percent of the nation’s power.

The PMAs’ mission is to market federal hydropower at the lowest possible rates that are consistent with sound business practices. The power the PMAs market is the power that remains after it has been consumed for project purposes—for example, to pump water to fields that are being irrigated. By law, the PMAs are to give priority in the sale of power to “preference customers”—public bodies (such as municipal utilities, irrigation districts, military installations, and other federal agencies) and cooperatives. Each PMA has its own specific geographic boundaries, federal water projects from which it markets power, statutory responsibilities, and operation and maintenance responsibilities. Except for the Alaska Power Administration, the PMAs generally do not own, operate, or control the facilities that generate electric power; the generating facilities are controlled by the operating agencies—most often the Bureau and the Corps. The PMAs, except for Southeastern, do own and operate transmission facilities. Southeastern relies on the transmission services of other utilities to transmit the power it sells to its customers.

The PMAs are generally required to recover all costs incurred as a result of producing, transmitting, and marketing power, including repayment of the federal investment in the power generating facilities and other debt, with interest. Certain nonpower costs are also allocated to power revenues for repayment. For example, under the concept of aid-to-irrigation, revenues earned from the sale of power repay the federal investment in irrigation facilities that the Secretary of the Interior deems is beyond the ability of irrigators to repay. According to Bureau officials, power revenues are ultimately expected to cover about 70 percent of the federal investment in completed irrigation facilities. As of September 30, 1996, the PMAs and TVA had an outstanding debt of about $52 billion related to financing the construction and operation of power plants, transmission lines, and related electricity assets, as well as other costs that are allocated to be repaid through revenues earned from the sale of electricity. TVA owed about $28 billion; Bonneville owed about $17 billion; and Southeastern, Southwestern, and Western owed the balance—about $7 billion.

Together, DOE’s five PMAs and TVA market power within 34 states. They do not serve Hawaii and states in the Northeast and upper Midwest. Figure 1.1 shows the service areas of the PMAs.

The Congress established the first PMA, Bonneville, by passing the Bonneville Project Act of 1937 to market federal power in the Pacific Northwest. (See app. III for a more detailed discussion of Bonneville.) In 1943, the Secretary of the Interior established Southwestern under the President’s war powers. The Flood Control Act of 1944 provided the authority to create PMAs and also gave the Secretary of the Interior jurisdiction over the Corps’ electric power sales. The Secretary of the Interior established Southeastern in 1950 and Alaska in 1967. The last PMA, Western, was authorized by the Department of Energy Organization Act of 1977, when the four existing PMAs were transferred from the Department of the Interior to DOE.

The largest individual federal power producer, however, is TVA, which by some measures is the largest utility in the nation. Providing about 5 percent of the nation’s power, TVA generates its own power and markets it in wholesale markets, as well as directly to large industrial customers. TVA also approves the retail rates charged by the 159 municipal and cooperative utilities that are its primary customers. In 1933, the Congress created TVA as a multipurpose, independent federal corporation to develop the resources of the economically depressed Tennessee River Valley: TVA was to improve navigation, promote regional agricultural and economic development, and control the flood waters of the Tennessee River. To those ends, TVA erected dams and hydroelectric power facilities on the Tennessee River and its tributaries. Today, the power program is by far TVA’s largest activity, with about $5.7 billion in annual operating revenues in fiscal year 1996. TVA’s hydroelectric facilities, coal-fired power plants, nuclear generating plants, and other power facilities—with a total generating capacity of over 28,000 megawatts (MW)—provide electricity to nearly 8 million people in Tennessee and parts of Alabama, Georgia, Kentucky, Mississippi, North Carolina, and Virginia. (See app. I for a more detailed discussion of TVA.)

The Government Also Makes or Guarantees Loans to Finance the Construction and Operation of Rural Electricity Systems

In addition to authorizing the sale of federal power in rural areas, the Congress passed laws to encourage the development of nonfederal power systems. IOUs were historically reluctant to serve sparsely populated areas because of the heavy capital costs involved in installing power systems and serving relatively few customers. As a result, in 1935, scarcely 1 in 10 farm households in the United States had electricity. The Rural Electrification Act of 1936 authorized the Rural Electrification Administration (now RUS) to provide loans and credit assistance to organizations that generate, transmit, and/or distribute electricity to small rural communities and farms. From fiscal years 1992 through 1996, RUS made or guaranteed 880 loans to rural utilities, some of which buy power from the PMAs. The outstanding balance on RUS’ loans and loan guarantees was about $32 billion as of September 30, 1996. (See app. II for a more detailed discussion of RUS.)

New Legislation and Technologies Serve as a Catalyst for Change in Electricity Markets

From 1935 through the mid-1960s, little change occurred in the way utilities satisfied demand for electricity and were regulated. For decades, they were able to meet increasing demand at decreasing prices because they achieved economies of scale through capacity additions and technological advances. During much of this period, demand for electricity grew at a faster rate than the gross national product. However, in 1976, electricity growth did not exceed overall economic growth, and in 1982 electricity consumption declined. These adverse trends for the electric utility industry were caused by such events as (1) the Northeast power blackout of 1965, which raised concerns about reliability; (2) the Arab oil embargoes of the 1970s, which resulted in increases in fossil fuel prices; and (3) the passage of the Clean Air Act of 1970 and its 1977 amendments, which required utilities to reduce pollutant emissions. Because of the decline in the rate of growth in demand for electricity, utilities could no longer assume that prior patterns in demand-growth would continue into the future. How to satisfy the future demand for power became an increasingly uncertain issue.

In addition, since the late 1970s, statutory and technological changes have created a climate for change in traditional electricity markets. In general, electricity markets are starting to evolve from domination by large, monopolistic IOUs to competition among IOUs, nonutility generators, power marketers, and others. In the future, electricity markets may evolve into ones in which electricity is a commodity. In addition, states are taking action to ensure that retail consumers will be able buy power from a variety of competing sources.

Federal Laws Encourage Competition

In 1978, the Public Utility Regulatory Policies Act and the Fuel Use Act encouraged the growth of a nonutility sector of the electricity business. These laws were passed to lessen the nation’s dependence on foreign oil and encourage alternative sources of power. The Public Utility Regulatory Policies Act required commercial utilities to buy power from nonutility generators, called “qualifying facilities.” These entities had to meet certain criteria specified by FERC for such matters as their ownership and operating efficiency. In addition, the act introduced the pricing of electricity on a competitive basis: As more nonutility generators entered the market, FERC began approving certain wholesale transactions that had rates that resulted from a competitive bidding process. Many of the qualifying facilities generated power in nontraditional ways—for instance, by using small hydropower plants, cogeneration, or renewable sources. Under the Fuel Use Act, electric utilities could not use natural gas to fuel new generating technology; however, these “qualifying facilities” could. They were able to take advantage of new generating technologies, such as combined-cycle gas turbine generation that can be built with less capital than larger power plants. Although the Fuel Use Act was repealed in 1987, qualifying facilities and small power producers had already gained a portion of the total electricity supply. For instance, according to the association of IOUs, in 1995 nonutility generators built about 60 percent of the nation’s new electric generating capacity.

The Energy Policy Act of 1992 was perhaps the most significant legislative catalyst for increased competition. It expanded nonutility markets by creating a new category of power producers—“exempt wholesale generators.” Like qualifying facilities, exempt wholesale generators do not sell their power in retail markets and own only very limited transmission facilities. Although FERC does not regulate exempt wholesale generators under the Public Utility Regulatory Policies Act, it regulates most of them as public utilities under the Federal Power Act. Under FERC’s regulations, exempt wholesale generators may charge market-based rates if they and their affiliates lack market power. Unlike the requirement under the Public Utility Regulatory Policies Act that utilities purchase power sold by qualifying facilities, there is no federal mandate that utilities buy exempt wholesale generators’ power. The Energy Policy Act also allows FERC, upon application, to order wholesale wheeling of electricity if such an order does not, among other things, unreasonably impair reliability. It is now possible for a municipal utility that is served by an IOU to seek cheaper power from a neighboring utility. The Energy Policy Act also authorized FERC to set transmission rates at levels that permit the utilities to recover all of the costs incurred in providing transmission services, including legitimate, verifiable, and economic costs.

In April 1996, pursuant to its authorities under the Federal Power Act, FERC issued a ruling on transmission access. Order 888 requires public utilities that own, control, or operate facilities that transmit electricity in interstate commerce to offer both point-to-point and network transmission services under terms and conditions that are comparable to those that they provide for themselves. Public utilities must offer those services through open-access, nondiscriminatory transmission tariffs containing minimum terms and conditions. In addition, Order 888 allows utilities the opportunity to seek recovery of certain stranded costs from those customers wishing to leave their current supply arrangements. However, according to the Deputy Director, FERC’s Office of Electric Power Regulation, the open-access provisions of Order 888 do not apply to the PMAs, among other entities. Therefore, FERC cannot order the PMAs to provide open transmission services on a general basis. Operating under its authority under the Federal Power Act, FERC can order the PMAs to provide transmission only on a case-by-case basis. However, to facilitate a unified national approach to open-access transmission, DOE directed its PMAs that have transmission facilities to publish generally applicable open-access transmission tariffs, including ancillary services, in a manner comparable to the service tariffs and other measures required of transmission owners and operators that are regulated under FERC’s final rule. In December 1997, Southwestern and Western filed open-access transmission service tariffs with FERC, pursuant to Order 888. The tariffs are to govern future access to available electric transmission and, according to DOE, are consistent with the tariffs of other wholesale transmission providers. Bonneville had filed its tariffs earlier.

Utilities Respond to Increased Competition

In response to the uncertainties about how the electricity market will change and how fast, utilities have begun to implement new strategies to compete. Some are acquiring other utilities or merging with them. After years of virtually no mergers, many mergers have been completed or proposed since the Energy Policy Act was enacted in October 1992. For example, for IOUs alone, from October 1992 to January 1998, over 40 mergers had been proposed and 17 had been completed, according to the Edison Electric Institute—the national trade association for IOUs. Utilities are also restructuring themselves and decreasing their operating costs through reorganizations and layoffs. Some utilities are changing how they plan to satisfy future demand for electricity and changing the types of resources they acquire. Because of uncertainty about market conditions, instead of continuing to plan to meet long-term load forecasts, utilities are focusing more on meeting more immediate demand for power. Thus, utilities are now tending to buy resources that are flexible and allow them to adapt quickly to changing market conditions, such as smaller natural gas-fired power plants and purchased power. Utilities are also retiring power plants if they believe those plants may become uneconomic after the industry is restructured.

In responding to competitive challenges, utilities are trying to compete for the business of other utilities’ wholesale customers and defending their business with existing customers. For example, as cited in our 1995 TVA report, Virginia Power cut one wholesale customer’s rates by 5 percent to fend off the marketing efforts of a neighboring utility.

Federal power suppliers have also taken actions to become more competitive. For example, after the departure of half of its industrial load, TVA froze its rates from 1986 through 1997, although a rate increase was approved for 1998. Moreover, Western recently announced a decrease of over 20 percent, effective October 1, 1997, in the composite rates of power it markets from hydropower plants in the Central Valley Project in California. In addition, according to DOE’s Power Marketing Liaison Office, Western began a process in fiscal year 1995 to restructure itself. The goals of this program included reducing federal and contractor staff from fiscal year 1994 levels by 24 percent, saving $25 million in costs annually, and reducing Western’s organizational units. For its part, Southwestern has adopted a program to reduce overhead costs by reducing targeted administrative positions, reducing the number of managers and supervisors, and eliminating one field office.

Several Factors Will Affect How Fast Competitive Markets Emerge

Electricity markets are not yet fully competitive but are moving in that direction. Although markets for wholesale transactions are becoming competitive, retail markets are still uncompetitive. Supporters of restructuring argue that markets will not be truly competitive until both wholesale and retail markets are transformed. In addition, other issues that need to be resolved include deciding (1) how stranded costs are to be recovered, (2) how electricity is to be transmitted in competitive markets, (3) how electricity is priced in these markets, and (4) how consumers at the retail level are to be offered a choice of power suppliers. Once restructuring is complete, retail electricity rates may fall between 6 percent to 19 percent by the year 2015, depending on the intensity of competition, among other factors, according to DOE’s EIA.

Recovery of Stranded Costs

Arguably the most significant issue that policymakers will face is how to recover the stranded costs associated mainly with building large baseload power plants and other assets under the old regulatory regimen. IOUs erected large amounts of nuclear generating capacity and entered into long-term purchased power contracts to serve existing and future loads. Under the traditional covenants between IOUs and their regulators, the capital and operating costs associated with those assets were recovered through rates. Now, with power generation costs dropping and prospects that competition will affect market prices, these high-cost plants are becoming uneconomical and the costs associated with them may be “stranded.” Estimates of the investment in such assets nationwide range from $10 billion to $500 billion.

The issue of how to recover stranded costs—that is, who should pay—is being debated. In addressing the recovery of stranded costs in the context of retail competition, some states have proposed “sharing the pain”: Utilities could recover or offset the stranded costs by taking mitigating actions (for example, by implementing accelerated depreciation of generating assets, writing off the book value of stranded assets, adjusting dividends to investors, or decreasing operating expenses); ratepayers could pay through rate increases that regulators hope will be temporary; or bonds could be sold to the public to pay off the stranded costs and to avoid rate increases. However, some consumer groups believe that since utilities incurred the costs, they should bear the burden of repayment. For example, an attempt to securitize the costs of a nuclear power plant failed in Connecticut’s legislature because opponents, including consumer groups, believed the issuance of bonds amounted to a “bailout” of the utility. Staffs of state public utility commissions have argued that because IOUs incurred stranded costs under the old regulatory compact, IOUs should be allowed to recover at least some of these costs before they must charge market prices for power. How stranded costs are divided between utilities and their ratepayers, the period of time allowed for their recovery, and how much the recovery of stranded costs affects rates will determine when retail markets become competitive and to what degree.

Transmitting Power in Competitive Markets

To promote competition, new methods must be found to transmit power. Under current transmission arrangements, wholesale customers frequently do not find it economical to buy power from a distant utility because it must be transmitted over the power lines of intervening utilities, each of which adds a transmission or wheeling tariff to the price of the power. For example, in 1995 during our review of the financial viability of TVA, we found that although an IOU in the Southeast offered power that was competitively priced, transmitting it to TVA’s customers through one intervening utility might increase the price by about 10 percent, rendering its delivered price uncompetitive. In addition, according to DOE officials, some of the power transmitted is lost over distances.

To facilitate competitive transmission of power, many state regulators and FERC are advocating the establishment of “independent system operators” (ISO). Utilities in a given geographic area would transfer the operation of their transmission assets to an independent party that would transmit electricity reliably, safely, and efficiently in a nondiscriminatory fashion. For example, California has established an Independent System Operation Restructuring Trust to award funding to parties that will assist in establishing an ISO to begin providing service in 1998. The PMAs are also participating in the formation of ISOs. For example, Western is negotiating with other utilities in the Southwest to establish the Desert Southwest Transmission and Reliability Operator (an ISO) as well as to participate in the California ISO. Concerns exist that such arrangements may be problematic from legal and constitutional viewpoints. According to Western officials, however, in Western’s agreements with other utilities pertaining to the ISO, Western is taking care to ensure that its obligations under federal law and its contractual agreements with preference customers are protected. For example, Western officials believe that, under language provided by the PMA and accepted by FERC on Western’s participation in the California ISO, nothing in the ISO’s tariff shall compel any person or federal entity to violate federal statutes or regulations or compel any federal agency to exceed its statutory authority as defined in applicable federal statutes, regulations, or orders lawfully promulgated thereunder. These provisions also state that if any provision of the tariff requires any person or federal entity to give an indemnity or impose a sanction that is unenforceable against a federal entity, the ISO shall submit to the Secretary of Energy or DOE official a report of the situation. The Secretary or other official will take the steps necessary to remedy the situation to the extent possible.

Pricing Power in Competitive Markets

State public utility commissions are also taking steps to facilitate competitive pricing of power. They have supported establishing power pools or exchanges. Under these arrangements, members buy and sell power through the pool or exchange it at a price that reflects market demand and that promotes competition between utilities and other suppliers. For example, under one method, generating companies could bid to sell their power to the pool. The pool would then establish hourly or spot prices based on these bids. In California, the power pool will publish prices every hour or half hour, to be viewed by electric customers, investors, and power marketers. With these visible price signals, wholesale and retail buyers will be able to make efficient purchasing decisions and adjust their consumption of power from peak to off-peak periods when prices drop.

Promoting Retail Competition

As of February 1998, all 50 states and the District of Columbia had considered reforming their respective retail markets, according to the National Regulatory Research Institute and records obtained from state regulatory agencies. At that time, at least 17 states had actually implemented plans to restructure the industry by enacting restructuring legislation or by adopting final orders. Regulators in these states hope that industrial, commercial, and ultimately residential consumers will be able to choose their power supplier, rather than being tied to one utility. These states hope to establish retail choice at all levels by 1998 at the earliest and 2005 at the latest. Supporters of retail competition hope that it will nearly complete the restructuring process for electricity markets and foster competitive pricing throughout the nation.

At the time we completed our review, states such as Montana, New Hampshire, and New York had asked utilities to implement pilot retail choice programs so that broad issues that could affect widespread competition later could be identified. Several states, such as Michigan, Pennsylvania, and Rhode Island, were implementing retail competition in phases—for instance, extending it first to industrial and commercial customers and then to residential customers. As mentioned previously, some states were addressing the issue of stranded cost recovery. In addition, at least 8 of these 17 states were also encouraging utilities to continue their “social” programs—such as energy efficiency and conservation programs, use of renewable sources of power, and low-income energy assistance programs. These programs can be funded by charging consumers a nonbypassable fee or by instituting a tax or surcharge on all energy services. Also, to foster competition and decrease utilities’ market power, public utility commissions were requiring utilities to “unbundle” their services—that is, to divest themselves of, or otherwise transfer, the generation, transmission, and distribution of power.

When restructuring is completed, states expect that retail customers will enjoy a variety of options for taking advantage of retail competition. For instance, the California Public Utility Commission expects that customers will use metered information about how much power they are using at specific times of day and how much that power costs. They could then decide which supplier to buy from during specific times to minimize costs. They may be able to negotiate directly with a supplier or use the services of an energy marketer or broker. In Maine, it is envisioned that consumers that are unwilling to shop for alternative suppliers will be able to adopt the “standard service option” from their existing utility. The existing utility will use a competitive bidding process in order to buy power for its ratepayers at prices that are comparable to today’s prices. Other options envisioned for Maine’s ratepayers include signing contracts with power marketers or aggregators that are short term, thus enabling them to buy power at a low price but with a risk of rate hikes or rate instability. They will also be able to buy power under longer term contracts at more expensive but more stable rates. Ratepayers will also be able to purchase “green power” (i.e., power from nonpolluting sources such as renewable sources). “Those states that are aggressively pursuing competitive restructuring are invariably high-cost states with little to lose. On the other hand, as a lower-cost state, Virginia may have little to gain and much to lose by being on the leading. . .edge of this restructuring movement. We should also take note of the slow pace of those mostly low-cost states surrounding Virginia—North Carolina, Tennessee, Kentucky, West Virginia, and Maryland. Consequently, Virginia should pursue a cautious and measured approach to adopting competitive initiatives, fully exploiting non-painful learning opportunities through observing the successes and failures of retail experiments and restructuring efforts in the more aggressive states.”

Furthermore, in Nebraska, a state where all electric power is provided by public entities and where power rates are among the nation’s lowest, the state’s largest electric utility has asked a federal appeals court to overturn FERC Orders 888 and 889. The utility challenged the orders on the grounds that FERC does not have the legal authority to impose on the utility the same regulatory regime that it imposes on private investor-owned electric utilities because the utility is a political subdivision of the state of Nebraska.

Objectives, Scope, and Methodology

Federal agencies that generate or market electricity and that make or guarantee loans to finance improvements to rural power systems incurred a debt of about $84 billion as of September 30, 1996. Three agencies that market federal electricity—the Southeastern, Southwestern, and Western—are responsible for $7 billion of this debt. They face an uncertain future as electricity markets become increasingly competitive. In response, the Chairmen of the House Committee on Resources and the Subcommittee on Water and Power asked GAO to focus on these three PMAs and to (1) examine whether the government operates them and the related electric power assets in a businesslike manner that recovers the federal government’s capital investment in those assets and the costs of operating and maintaining them and (2) identify options that the Congress and other policymakers can pursue to address concerns about the role of these three PMAs in restructuring markets or to manage them in a more businesslike fashion. GAO’s options also apply to the Corps and the Bureau, which generate most of the power these PMAs market. Although GAO’s options apply only to these agencies, the report also provides information about TVA, RUS, and Bonneville in appendixes I, II, and III, respectively.

We also included in this report information from generalized reports on how federal agencies can be operated in a more businesslike fashion. See Related GAO Products at the end of this report for a list of the products used to prepare this report.

We conducted our review from April 1997 through February 1998 in accordance with generally accepted government auditing standards. Appendix IV contains a detailed description of our objectives, scope, and methodology.

We provided a draft of this report to DOE’s Power Marketing Liaison Office that represented the views of Southeastern, Southwestern, and Western; the Department of the Interior (including the Bureau); the Department of Defense (including the Corps); Bonneville; and FERC. Their comments and our responses are included in appendixes VI, VII, VIII, IX, and X, respectively.

The Federal Power Program Operates at a Net Cost, Has Generating Assets That Need Repair, and Presents Some Risk That the Federal Investment May Not Be Recovered

Federal laws and regulations generally require that the PMAs recover the full costs of producing and marketing federal hydropower. The PMAs generally follow these laws and regulations; however, in some cases federal statutes and DOE’s rules also prohibit or are ambiguous about the recovery of certain costs. As we reported in September 1997, for fiscal years 1992 through 1996, as a result of its involvment in the electricity-related activities of Southeastern, Southwestern, and Western (the three PMAs), the federal government incurred “net costs” of $1.5 billion—the amount by which the full costs of providing electric power exceeded the revenues from the sale of power. In addition, the availability of many federal power plants to generate electricity is below that of nonfederal plants because, among other factors, the federal plants are aging and because the federal planning and budgeting practices, including those used by the Bureau and the Corps, do not always ensure that funds are available so that repairs can be made when they are needed. The resulting declines in performance decrease the marketability of federal power. The net cost to the Treasury and the performance problems of the federal power plants—when combined with competitive pressures on electricity suppliers to decrease their rates at a time when some federal hydropower project’s environmental costs need to be recouped by the PMAs—create varying degrees of risk that some of the federal investment at certain federal generation and transmission projects and rate-setting systems will not be repaid. For example, although the recovery of most of the federal investment in the three PMAs’ hydropower-related facilities is relatively secure, up to $1.4 billion of the federal investment for projects or rate-setting systems pertaining to these PMAs, out of a total federal investment of about $7.2 billion, is at some risk of nonrecovery.

The Federal Program Does Not Recover All of the Costs of Generating, Transmitting, and Marketing Power

As noted in two of our recent products, the revenues of the government’s power generating and marketing activities are not recovering all of the costs associated with the program. These activities operate at a net cost (loss) to the U.S. Treasury. For the three PMAs that are the focus of this report, net costs of $1.5 billion were incurred for fiscal years 1992 through 1996. These net costs fall into several categories: (1) net financing costs, (2) unrecovered employee benefits, (3) unrecovered construction costs, and (4) other costs.

Net Financing Costs of the Three PMAs

We estimate that the net financing costs for the three PMAs’ appropriated debt in fiscal years 1992 through 1996 was about $1.2 billion, including $208 million in fiscal year 1996. These costs stem primarily from appropriated debt provided by the federal government at low interest rates with favorable repayment terms. Appropriated debt carries a fixed interest rate and cannot currently be refinanced. Also, the Treasury cannot require the PMAs to repay the debt before it matures. The interest the PMAs pay on their outstanding appropriated debt is often substantially below the rate the Treasury incurred to provide funding to the PMAs. The PMAs’ average interest rate on outstanding debt was 3.5 percent, whereas the Treasury’s weighted average interest rate on outstanding bonds was 9 percent to provide funding to the PMAs. The PMAs have incurred substantial amounts of appropriated debt at low interest rates primarily because, in accordance with the appropriate DOE order, they repay high-interest debt first, and because the appropriated debt they incurred before 1983 was generally at the below-market interest rates in effect at the time.

PMAs’ Rates Do Not Recover All Employee Benefit Costs

For current PMA and operating agency employees, the federal government incurs a portion of the cost for Civil Service Retirement System pensions and almost all of the cost for postretirement health benefits. For fiscal years 1992 through 1996, we estimate that the net cost to the federal government of providing these benefits was about $82 million for the three PMAs, including $16 million in fiscal year 1996. The PMAs plan to begin recovering the full annual cost of pension and postretirement health benefits in fiscal year 1998.

PMAs’ Rates Do Not Recover All Construction Costs

We found that the three PMAs had incurred costs or had costs allocated to them by the operating agencies for which full costs were not being recovered through the PMAs’ rates. These costs were for the few projects that were not yet completed, were under construction, or were canceled. In some cases, this situation occurred because the power generating projects had never operated as designed. In accordance with DOE’s guidance, the PMAs set rates that exclude the costs of nonoperational parts of the power projects, including capitalized interest. For example, at the Corps’ Russell Project (located on the Savannah River, which serves as the border between Georgia and South Carolina), partially on line since 1985, litigation over large fish kills has kept four of the eight turbines from becoming operational. As a result, over half of the project’s construction costs—about $500 million—have been excluded from Southeastern’s rates. The net costs of these construction projects for fiscal year 1996 represent capitalized or unpaid interest incurred in that year. For construction projects designed to generate power marketed by the three PMAs, we estimate that for fiscal years 1992 through 1996, the cumulative net costs are $138 million, including $30 million in 1996. The PMAs believe that in most instances, including the Russell project, these net costs will be recovered in future years.

PMAs’ Rates Do Not Recover Some Other Costs

The three PMAs also incurred other net costs that totaled $157 million for fiscal years 1992 through 1996, for such purposes as environmental mitigation and irrigation. In an example involving environmental mitigation, at the Central Valley Project’s Shasta Dam in California, the 1991 Energy and Water Development Appropriations Act specified that any increases in Western’s costs to purchase power because of bypass releases to preserve fisheries downstream should not be allocated to power; instead, they were paid for by appropriated funding. These costs totaled about $15.3 million in fiscal year 1996 and about $53.8 million for fiscal years 1992 through 1996. In another example of net costs related to irrigation, in May 1996 we estimated that about $454 million in (1) the federal investment in hydropower facilities allocated to irrigation at the Bureau’s Pick-Sloan Missouri Basin Program and (2) a portion of the costs associated with storing water for these projects were not likely to be recovered without congressional action. The principal of $454 million had grown to $464 million as of September 30, 1996. As, by law, interest on this amount is not being paid, we estimated that about $70.6 million in interest was unpaid for fiscal years 1992 through 1996.

The Federal Hydropower Assets Need Repair

The availability of federal power plants to generate power is below that of other power plants. Many federal plants are aging (the Bureau’s plants average about 50 years in service and the Corps’ about 30 years), which increases the need for repairs. At the same time, the Bureau’s and the Corps’ planning and budgeting processes do not always provide funding to repair the federal power assets when the funding is needed, causing some repairs to be delayed and the power plants to become less available to provide power.

According to the representatives of the PMAs’ power customers and our previous work, the maintenance needs of the Bureau’s and the Corps’ hydropower plants are often underfunded or maintenance is delayed. Furthermore, data from both operating agencies show that their power plants are generally less available to generate power than power plants operated by other generators of electricity. For example, according to the Bureau’s 1996 benchmarking study, while the agency’s power plants exceeded the performance of the industry in terms of wholesale firm rate, production costs/kWh, and the number of full-time operation and maintenance employees per generating unit, they lagged behind other nonfederal and federal hydropower producers in availability, forced outage, and scheduled outage factors. However, the availability of the Bureau’s hydropower plants over the last 3 years has been above the average availability of the last 15 years. In our 1996 testimony, we reported that in the Corps’ South Atlantic Division, the availability of hydropower plants declined from about 95 percent in 1987 to 87 percent in 1995. In addition, the 1995 availability of the Corps’ units is below the industry average (89 percent availability) in the Bureau’s benchmarking study. Several hydropower plants have been off line for several years because of forced outages. However, DOE’s Power Marketing Liaison Office notes that maintenance problems differ by region, district, or division within the operating agencies and that problems in one area should not be extrapolated to all areas.

The planning and budgeting processes that federal agencies—including the Bureau and the Corps—use are not conducive to predictable planning and funding of needed repairs. Pursuant to key laws, including the Antideficiency Act, the Adequacy of Appropriations Act, and the Budget Enforcement Act, federal agencies cannot enter into obligations prior to an appropriation and cannot exceed appropriations unless they have specific statutory authority to do so. Thus, they cannot enter into contracts that obligate them to pay for goods or services unless sufficient funds are available to cover the costs in full. Therefore, agencies must budget for the full costs of contracts up front. Agencies cannot enter into a contract unless it is authorized by law and an appropriation covers the contract’s cost. Moreover, fixed spending limits, or caps, apply to all discretionary spending through 1998, including spending for capital items. As we reported in 1996, agency officials often pointed to the poor condition of federal power plants as evidence of a need for more capital spending and reformed budgeting. Some observers add that increased capital spending is needed to generate operational savings in the future. They believe that in an era of constrained federal budgets, spending on capital projects is limited because it entails heavy initial costs and the budget “scoring” for such projects occurs in a single year, while the benefits of it extend for many years.

PMAs and their customers stated that they view the federal planning and budgeting processes as not being well adapted to a commercial activity, such as operating a power system. Under current planning and budgeting systems, the project and field locations of the Bureau and the Corps identify, estimate the costs of, and develop their budget proposals, not only for hydropower but also for such facilities as dams, irrigation systems, and recreational facilities. Hydropower repairs may be assigned lower priorities than other items. Budget requests also have been subject to 10-percent to 15-percent reduction targets at the operating agencies. Under these conditions, the operating agencies, the PMAs, and the PMAs’ hydropower customers believe that funding for needed repairs is at best uncertain and at times is unavailable when needed. To ensure that the funding of hydropower maintenance and repair activity receives the funding priority they believe it deserves, customer groups are encouraging the operating agencies to consult them about budgeting and planning for operation and maintenance. Customer groups are also encouraging the federal agencies to seek alternative funding. In most cases, the customers are willing to provide up-front financing for repairs if they are granted more input to planning and budgeting decisions, according to DOE’s Power Marketing Liaison Office.

Risk of Nonrecovery of Some Federal Investment Exists

In our September 1997 report, we found that the risk exists that some portion of the government’s investment in its power generation and sales program may not be recovered. The total amount of investment in the assets of the power generating and marketing programs of the operating agencies, the three PMAs, Bonneville, and TVA was about $52 billion. This risk stems from several factors, two of which have been addressed already in this report. First, the large net costs of the federal hydropower program will continue if action is not taken to recover all of the costs of operating the program. Second, the degraded availability of the generating assets contributes to this risk of nonrecovery because it decreases the marketability of federal power. Other factors also add to the risk of nonrecovery. One factor is that the onset of market competition puts pressure on suppliers to keep their electric rates low or to decrease them. At the same time, the PMAs are being pressured to raise some rates because of the costs at certain projects for mitigating the damage to fish and wildlife habitat from hydropower generation. Moreover, when the operating agencies have had to curtail power generation at particular projects to protect the environment, the PMAs have had to purchase power to fulfill their contracts—another factor that puts upward pressure on the PMAs’ rates.

Trend Toward Lower Market Rates Creates Some Risk of Nonrecovery of the Federal Investment

Nationwide electricity rates have dropped over 25 percent after inflation since 1982. According to DOE’s Energy Information Administration, retail rates fell from a nationwide average of 8.7 cents per kWh in 1982 to 6.3 cents in 1996 (constant 1992 dollars). This decrease has been caused by factors that include declining fuel prices, an increasing number of fully depreciated power plants, more efficient power generation, and competition from nonutility generators. According to various industry analysts, the restructuring of electricity markets will cause market rates to continue to decline. In addition, according to the Energy Information Administration, retail rates nationwide in 2014 may be about 6 percent to 19 percent below the levels they would have been if competition had not begun. In some cases, wholesale power is available today at about 2 cents per kWh. For example, according to the customer group of the Colorado River Storage Project, in May 1997 one Western customer signed a 20-year contract with an IOU to purchase firm power at a rate not to exceed 1.8 cents per kWh. In contrast, Western’s composite rate for power from the project was about 2 cents per kWh. If the PMAs’ customers can buy less expensive power from sources other than the PMA, the fixed costs associated with the federal government’s power assets will need to be recovered from a decreasing number of customers, placing increased pressure on the PMA to increase its rates. This pressure, in turn, will encourage additional customers to seek power from other sources.

Environmental Mitigation Costs Also Add to the Risk of Nonrecovery

At the same time that wholesale and retail rates are declining, the PMAs are being pressed to raise rates at some projects, primarily because of the need to address concerns about damages to the environment and endangered species. As a result, the three PMAs’ hydropower programs have lost revenues, have had to buy more costly replacement power to fulfill their contacts with their power customers, and in some cases have had to spend millions of dollars to mitigate environmental effects. For example, according to DOE’s Power Marketing Liaison Office, about one-third of the 1,356 MW capacity at the Bureau’s Glen Canyon Dam in Arizona, whose power is marketed by Western, could be lost because power generation has been restricted to protect recreational resources and endangered fish species. The Bureau estimates that Western has lost more than $100 million in revenues. At the same time, Western’s costs to buy power to replace the lost generating capacity have averaged about $44 million per year. Furthermore, at the Bureau’s Shasta power plant, in California, whose power Western also markets, restrictions on the turbine operations and cold water bypasses to protect the winter run of the chinook salmon resulted in about $50 million in additional costs to purchase power for Western since 1987. Moreover, the shutdown of some units at the Corps’ Russell project because of litigation over fish kills resulted in Southeastern’s losing $36.1 million in revenues per year since fiscal year 1994.

Up to $1.4 Billion of Federal Investment in the Power Assets of the Three PMAs Is at Risk of Nonrecovery

As we recently reported, some portion of up to about $1.4 billion in federal investment is at varying degrees of risk of not being recovered through power revenues at three generation projects, one transmission project, and two rate-setting systems pertaining to the three PMAs. As of September 30, 1996, the three PMAs had accumulated over $7.2 billion in debt for constructing and upgrading the Bureau’s and Corps’ generating facilities whose power the three PMAs market, the PMAs’ transmission facilities, and the Bureau’s irrigation facilities, which are largely repaid with power revenues. In general, the recovery of most of this investment is seen as relatively secure because the three PMAs are generally competitively sound: Their cost to generate power, measured in terms of average revenue per kWh, was 40 percent or more below nonfederal utilities for 1995. However, at some projects, congressional action will be needed to ensure that large amounts of federal investment are recovered. For example, at the Pick-Sloan Program, $464 million in federal investment in power facilities and reservoir storage cannot be recovered until the associated irrigation projects come into commercial service. Because most of these irrigation projects are infeasible, the $464 million cannot be repaid. Without congressional action to force a reallocation of these costs from irrigation to power, or a related solution, recovery cannot take place. Recovery of these costs would place upward pressure on Western’s electricity rates—potentially entailing a one-time increase of up to 14.6 percent. At a time that wholesale electric rates are decreasing, such increases in the PMAs’ rates are uncompetitive and could erode the marketability of the federal power if they are numerous and continuous. Table 2.1 contains information about the circumstances surrounding the $1.4 billion at risk. Additional details on the situations at these six projects or systems are presented in appendix V.

Conclusions

More competitive electricity markets will offer new benefits to consumers while posing a special challenge to the federal government’s program to generate and market power. With competition at the wholesale and retail levels, ratepayers are likely to enjoy unprecedented opportunities to choose from among several competing suppliers offering a variety of prices and services. However, the problems we have reported in recent years, combined with these market changes, should alert policymakers to take steps to protect the investment in the federal power assets.

Even in the absence of market changes, the agencies that provide power are over $50 billion in debt, including about $7 billion for the three PMAs. At the same time, the hydropower assets are degrading in terms of their availability to generate power, thereby making the power they generate less marketable. As competitive markets develop, some PMA customers may opt to buy from other suppliers if the PMAs’ power is perceived as being increasingly unreliable. In addition, although the PMAs’ power is very competitively priced, this advantage may not last. Specifically, competition is expected to cause market rates to fall. At the same time, the PMAs’ rates need to cover the costs of environmental impacts downstream. If the PMAs’ rates increase and the wholesale rates for power fall to the point where the two rates converge, the PMAs may lose customers to other suppliers. At the Central Valley Project and the Colorado River Storage Project, Western’s wholesale power is already priced at levels competitors can challenge.

If the PMAs lose customers to other suppliers, then the risk increases that the federal investment in the power program will not be recovered. As documented in this chapter, for the three PMAs’ projects and rate-setting systems, some portion of $1.4 billion is already at risk for nonrecovery. Although most of the risk to the $1.4 billion does not stem from increasing competition, the advent of competition does heighten the risk of nonrecovery. As discussed in the next chapter, options are available to the Congress and the agencies themselves to better recover costs and protect the federal investment, among other benefits.

Options for Operating Federal Hydropower Assets

The nation’s electricity markets are undergoing significant changes, as the previous chapters have shown. The speed with which this widespread restructuring may be completed is uncertain; however, it is ongoing and will continue, perhaps at an accelerating pace, as proposals to expand competition to the retail electricity market continue to be made by national and state policymakers, electric utility interest groups, and the Congress. As the industry becomes less regulated and more competitive at both the wholesale and retail levels, nonfederal utilities and power suppliers have taken important steps to become competitive to survive. Federal power agencies also face the challenge of moving to a more competitive environment. The entities to whom the PMAs sell power, aware that they need to supply the cheapest available power to their own retail customers, have begun to pressure the PMAs, the Bureau, and the Corps to adopt business practices that are better suited to the new era. Furthermore, and perhaps most important, these agencies are under pressure to adapt to the new markets to reduce the risk that the multibillion-dollar federal investment in hydropower and other associated programs will not be repaid if federal power ultimately proves to be too unreliable and overpriced to be competitive. In this connection, a widening recognition exists today that options for operating federal hydropower assets need to be considered and ultimately implemented. Three broad options exist for addressing the federal hydropower program’s operations:

Preserve the status quo of federal ownership.

Maintain federal control of the hydropower assets but manage them in a more businesslike manner.

Divest the federal hydropower assets.

Preserve the Status Quo

The federal power program uses low-cost hydropower generated at major federal water projects to help meet the needs of the preference customers, many of which are located in rural areas. The power plants at these water projects are generally operated by the Bureau and the Corps—the operating agencies—and the power that exceeded the project’s operational requirements is marketed by the PMAs, as described in chapter 1. Power is generated and marketed in a way that balances how the water is being used for the other purposes of the projects. Funding for the activities of the operating agencies and the three PMAs is subject to the annual congressional appropriation process under which the agencies obtain their funding for capital investments as well as for operations and maintenance expenses.

PMA and operating agency officials and representatives of the PMAs’ customer associations have indicated a need to change how the federal hydropower program is being operated. They stated that the agencies’ planning and budgeting processes do not provide sufficient, predictable, and timely funding to facilitate the repair of the federal power plants. In addition, they pointed to various administrative and legal requirements that they believe cause the PMAs and operating agencies to generate and market power in an unbusinesslike manner. In this connection, they have advocated ways to manage the federal hydropower assets, discussed in the next section, that will address these concerns.

Some representatives of the PMAs’ preference customers have advocated defederalizing the PMAs and the federal generating assets as a way of improving their operating efficiency and availability. For example, according to an official of an association of Western’s municipal power customers, the preference customers should purchase the federal generating and transmission assets of the Colorado River Storage Project in order to avoid the sharp rate increases that characterized Western’s rates from the project since the late 1980s. It is important to note, however, that other preference customers continue to support continued federal ownership of the dams, reservoirs, and hydropower assets. These customers believe that, although some changes in the PMAs’ current practices could lower operating costs and improve efficiencies, as a whole the PMAs have offered high-quality, low-cost services while balancing the diverse needs of the beneficiaries of the federal multi-use projects.

Moreover, representatives of investor-owned utilities or proponents of divestiture have questioned why the federal government continues to provide power in restructuring markets. First, electrifying rural areas was an important goal of the federal power program; however, this goal has been largely satisfied. Therefore, the need for the federal government’s involvement is questionable. Second, competition likely would enable wholesale and retail customers to choose from among competing power suppliers. This possibility again questions the need for the federal government to sell power. Third, the issue of providing low-cost PMA power to portions of 34 states in the South and West where the preference customers of the PMAs are located, but not to other areas, is debatable. And fourth, IOUs and other critics of PMA power state that, as federal agencies, the PMAs have advantages that IOUs do not have and therefore would compete with their nonfederal parties on an uneven basis. For example, our work has shown that the PMAs have rates that do not recover all of the costs of generating, transmitting, and marketing power. Also, as federal agencies, the PMAs are not subject to income taxes or state regulatory oversight and have more flexible repayment and rate-setting methodologies. Fifth, the status quo continues the existing risk of nonrepayment of the federal investment.

Because of the stakes involved in changing the management and ownership of federal water projects and hydropower plants, maintaining the status quo affords policymakers the opportunity to make careful decisions about how to proceed. The federal government’s role in balancing the multiple uses of water is important. It affects such things as how much water will be available to accommodate the expansion of metropolitan areas, how much water will be used to protect endangered species, and how much water will be needed to protect the harvesting of shellfish in the Apalachicola Bay, Florida. The Bureau and the Corps generate power while balancing these impacts. Any decisions that federal policymakers reach about changing how power is generated or how the water projects will be managed or owned will need to consider the impacts of the decisions on the uses of the water and the beneficiaries of the water projects. An advantage of the status quo is that it continues the federal role in balancing the multiple uses of the water and allows policymakers time to study these issues before they change the operations and/or ownership of the water and the power assets. Also, by preserving the existing multiple uses of the water projects and the projects’ beneficiaries, the status quo avoids the debate that is likely to occur if the Congress reexamines the agreements reached decades ago on federal involvement in power. For example, the status quo continues federal power’s role in helping promote the economies of rural areas, especially by providing inexpensive power to these areas for homes, businesses, municipalities, and irrigation. Many of the cooperatives that currently receive PMA power also have received direct loans or guarantees from RUS. According to Western officials, these cooperatives’ financial health depends in part on the availability of low-cost PMA power. This is of significant interest to the Treasury because of its need to recoup the balance these PMA customers owe in RUS’ loans or loan guarantees.

Under the status quo, the PMAs’ revenues are to repay billions of dollars of the costs associated with joint and nonpower benefits for purposes such as irrigation and fish and wildlife protection. Because such benefits likely would not cease to exist if power revenues stopped paying for them, other sources of revenues would have to be located to fund them. In order to avoid increasing the federal deficit, one possible means of paying for these benefits would be for the Congress to fund them from increased tax receipts. However, if federal taxes and revenues could not be increased, then the Congress would need to offset the spending increase for the benefits by decreasing federal spending for other purposes. Alternatively, some costs could be allocated to categories that are not reimbursable through power rates or user fees—to flood control at the Pick-Sloan Program, for example. However, in such a case, additional revenues (such as new taxes or new user fees) would be needed to pay for the costs or offsetting budget cuts to avoid increasing the budget deficit. In these cases, because of the need to find new revenues, uncertainty about repayment of the full Treasury investment would increase.

Maintain Federal Ownership but Improve the Management of the Power Program

Many options exist for improving the operations of the hydropower program while continuing federal ownership. These options can be grouped in several different ways, including (1) improving the planning, budgeting, and funding for capital repairs of the federal hydropower assets; (2) changing the PMAs’ power rates and repayment methodologies; (3) organizationally restructuring the federal hydropower program to improve its operating efficiency; and (4) eliminating the application of selected legal and administrative requirements to the federal program. In addition, the government could dispose of its high-cost hydropower projects. Some changes can be made by the PMAs and the operating agencies themselves, while others would require congressional action.

Improving the operating efficiency of the federal hydropower program would not fully respond to the concerns of the advocates of complete divestiture or privatization, who believe that the government should not participate in a commercial activity. Those concerns could be satisfied only if the hydropower assets were fully divested; however, improving their operations under federal ownership would better safeguard the federal investment while continuing to balance the existing multiple purposes of the projects. Adoption of these improvements may have immediate benefits or may be considered an interim step toward full divestiture, if the Congress proceeds with that option.

Improving Capital Planning, Budgeting, and Funding for Repairing the Federal Hydropower Assets

Federal agencies are traditionally funded through annual appropriations from the Congress. However, as stated in chapter 2, the federal budget process does not lend itself effectively to commercial activities. Under the current planning and budgeting process, the Bureau’s and the Corps’ project and field locations estimate the costs of and develop the budget proposals for capital repairs of not only hydropower facilities, but also dams, irrigation systems, navigation systems, and recreational facilities. Hydropower repairs may be assigned lower priorities than other items, and budget requests are also subjected to 10-percent to 15-percent reduction targets to reduce the federal deficit. Under these conditions, the PMAs’ power customers believe, and our previous work showed, that funding for needed repairs is at best uncertain and at times is not available when it is needed.

Several alternatives present themselves for better ensuring that the federal hydropower resources are repaired in a timely fashion. Capital planning and budgeting could be instituted for the federal hydropower program. If the PMAs and the operating agencies were to adopt more businesslike capital planning and budgeting practices, they would be better able to systematically identify and fund improvements and repairs to their power systems. In addition to capital planning and budgeting, other approaches have been adopted. For instance, PMAs, operating agencies, and preference customers have reached agreements allowing customers to finance some capital repairs.

Institute Capital Planning and Budgeting

The Bureau and the Corps need to improve their planning and budgeting process to facilitate timely repairs of their hydropower facilities. The Corps’ need was illustrated in our 1996 testimony on reliability issues at the Corps’ hydropower plants in the Southeast. The Corps recognized that long-term, comprehensive planning and budgeting systems are needed to identify and fund key repairs and rehabilitations at its hydroelectric power plants, especially in the current environment of static or declining budgets; however, under its current planning and budgeting system, its funding decisions cannot be based on such processes.

Operating under the federal budgeting process, the Corps finds itself unable to ensure a predictable source of funding for capital projects at a time when its budget has been decreasing. Therefore, it gives priority to routine, ongoing maintenance and performs reactive, short-term repairs when its power plants experience unplanned outages. The federal budgeting process does not lend itself to funding extensive repairs and rehabilitations; when these actions eventually become essential, the Corps’ budgeting process requires extensive justifications that can take a year or longer to complete.

During the early 1990s, the Corps was beginning to address its planning and budgeting needs, for instance, by beginning to rank proposed repair and rehabilitation projects. This effort was suspended in fiscal year 1995, but the Corps’ responsible headquarters official planned to direct the field locations to undertake the effort in time to be considered for the fiscal year 1998 budget. Moreover, in recognition of the need to spend more to repair and rehabilitate its hydropower plants, the Corps in fiscal years 1993 through 1997 requested appropriations for major rehabilitations of some of its hydropower plants. Ten major rehabilitation projects have been approved for funding during fiscal years 1993 to 2007, with a total cost of about $450 million. These projects are being funded from the Corps’ Construction-General account generally over a multiyear period and do not need to be re-budgeted annually.

As described by Bureau officials, the Bureau’s planning and budgeting process, like the Corps’, is lengthy and complex, taking over 2 years to produce a known budget level. Because 10-percent to 15-percent budget cuts are applied to the initial budget and subsequent proposals made by the regions and their area offices, future funding levels are uncertain. For example, Bureau officials in the agency’s Billings, Montana, regional office, described the lengthy budget process they expected to undergo to achieve a budget for fiscal year 2000. From the regional perspective, the process began in August 1997 when the regional office received the initial budget proposals from its area offices. During the ensuing 16 months, scheduled to end in December 1998, the area offices, the region, the Bureau’s Denver Office, the Bureau’s Washington Office, the Office of the Secretary of the Interior, and the Office of Management and Budget will review, discuss, and repeatedly revise the proposed area office and regional office budgets, resulting in a consolidated budget for the Bureau and the Department of the Interior. Although by December 1998 the Department will have informed the regional office of expected funding levels for fiscal year 2000, certainty about expected funding levels will not be attained until some time between February 1999, when the Office of Management and Budget will assemble and convey the President’s budget to the Congress, and October 1, 1999, the start of fiscal year 2000.

Implement Alternative Forms of Financing

Funding from sources other than federal appropriations has been suggested as one option to improve how the PMAs and the operating agencies pay for repairs of the federal hydropower assets. Although use of nonfederal funds to finance federal agencies’ operations is generally prohibited unless specifically authorized by the Congress, several forms of alternative financing have been authorized by the Congress, according to agency officials.

Through one type of authorized arrangement, referred to, among other names, as “advance of funds,” nonfederal entities, such as preference customers, pay for repairs and upgrades of the federal hydropower facilities. Under federal budget statutes, such funding must be ensured before work on a project can be started. For example, Western’s customers are providing advance funding to renovate the generating units at the Bureau’s Shasta power plant in the Central Valley Project. Under an agreement between the Bureau, Western, and the preference customers, the customers may finance up to $21 million and deposit the funds in an escrow account to pay for the work. The Bureau accepts the customers’ funds under the Contributed Funds Act.

Customers may be repaid in various ways, including offsets to power rates under which (1) expenses funded from advances from customers are excluded from the revenue requirement for repayment purposes or (2) customers’ monthly power bills are credited for the amount each customer paid to the escrow account. In the case of the Shasta power plant, the customers who contributed funds will be issued credits on their monthly power bills from Western; those that did not contribute funds will not be issued credits. According to the Bureau, this arrangement ensures that all customers contribute. When completed, the entire repair cost will have been expensed throughout the construction period with advance funding from PMA customers.

Under another form of alternative financing, referred to as “net billing,” invoice amounts are netted out among parties who perform work or provide services for each other, resulting in the issuance of one check instead of multiple checks. Net billing has been used for purchased power and wheeling for several projects—Central Valley, Loveland Area, and Pick-Sloan, according to Western officials. Western estimates that the use of net billing has reduced appropriation requirements by between $40 million to $50 million annually.

Under a variation of net billing, referred to as “bill crediting,” a customer agrees to pay one or more of the PMA’s bills in exchange for an equivalent credit on the customer’s power bill. Bill crediting has the same uses as net billing. Western estimates that bill crediting has reduced appropriations’ requirements by between $45 million to $60 million annually, mostly in the Central Valley Project, and that increased use for the Loveland and Pick-Sloan projects could reduce the appropriations’ requirements by between an additional $2 million to $7 million annually.

Supporters of alternative financing, among them officials from the Bureau, the Corps, the PMAs, and the PMAs’ customers, note that its use allows repairs and improvements to be made more expeditiously and predictably than through the federal appropriations process. They believe that alternative financing could provide more certainty in funding repairs and help address problems such as deferred maintenance at Corps-operated plants that provide power marketed by Southeastern. Alternative financing would also move certain costs out of the budget cycle, decreasing the need for appropriations that must be repaid through the PMAs’ power revenues. For example, as of January 1998, Bonneville had entered into long-term agreements with the Bureau and the Corps that will allow Bonneville to directly fund about $150 million dollars in capital improvements and operations and maintenance of the federal hydropower assets in the Pacific Northwest. According to Bonneville, these arrangements will shorten the time needed to secure funding for repairs and maintenance and will remove maintenance as a funding item that must compete with other federal budget priorities. The agreements also promote coordination between Bonneville, the Bureau, and the Corps in budgeting for future maintenance and repairs. Bonneville estimates that this closer coordination will produce operating efficiencies that can reduce costs by up to about $48 million per year.

However, Corps and DOE officials cautioned that expanded use of alternative financing may not be prudent because, depending on how it is implemented, oversight by the Congress and the Office of Management and Budget may decrease. According to Bureau and DOE officials, the Congress could take action to foster oversight by the Congress and other entities. For example, Bureau officials believe that to provide for oversight, the agencies could be required to submit data on expenditures to the Office of Management and Budget and to the Congress.

Expanded use of alternative financing may require legislative action, especially for the projects operated by the Army’s Corps of Engineers. In a July 1996 memorandum, the Army’s Office of the General Counsel concluded that although the Army has some existing authority to accept funds from outside parties to finance replacements, improvements, and other work at the Corps’ hydropower facilities, the use of these funds must be reviewed case by case and is limited to funds from states and their subdivisions. According to the memorandum, the Congress may have to enact more specific legislation to (1) clarify the terms under which such funds may be accepted, including the kind of work that they could pay for, and (2) establish the framework under which the Army, the PMAs, and the customers should proceed with such alternative financing.

Establish Additional Revolving Funds

The Congress could expand the use of revolving funds. Under one revolving fund arrangement, a fund established by a one-time permanent appropriation is replenished through revenues, which, in the case of the PMAs, are generated by the sale of power or other services and credited directly to the fund, instead of being replenished through annual appropriations. The Congress has authorized the use of these funds at such projects as the Colorado River Storage and Fort Peck projects to fund operation, maintenance, and replacement costs.

Proponents of revolving funds, including some officials of Western, the Bureau, and a PMA customer group, note that the funds allow repairs and improvements to be financed more expeditiously and predictably than the federal appropriations process does. Like alternative financing, revolving funds remove some costs from the budget cycle, thereby decreasing the need for reimbursable appropriations. Thus, revolving funds enable the federal power-related operations to be self-financing and also offer customers more opportunities to consult with the agencies on how to spend funds to repair and maintain the hydropower assets.

However, officials of PMA customer groups and the Office of Management and Budget also stated that the use of revolving funds could reduce oversight by external parties such as the Congress and the Office of Management and Budget and/or may allow repayment obligations to be incurred that are not routinely approved by these entities. However, the Congress could be kept informed of the operating agencies’ and the PMAs’ spending plans through the annual appropriations process. For example, the PMAs could be required to submit their annual operations and maintenance budgets to the congressional oversight committees. A 1993 DOE legislative proposal, which was not enacted, would have provided for separate accounts established in the U.S. Treasury to be funded from all sources, including sales of power and other services as well as other collections by, contributions to, and appropriations for Southeastern, Southwestern, and Western. These PMAs, the Bureau, and the Corps would use these accounts to pay for the operations, maintenance, and rehabilitation of their power assets. The PMAs would have submitted their annual operations and maintenance (O&M) budgets to their budget committees, including estimates of the PMAs’ and the operating agencies’ O&M spending, project by project. Officials of the Bureau, Western, and a PMA customer group voiced concerns that revolving funds increase the likelihood that nonpower costs, such as environmental initiatives and repayment of obligations to Native Americans, will be added to the revenue requirements base, with rate impacts that are not fully apparent until later. For example, under bills proposed in both the House and the Senate, a potential future cost of up to about $4.5 million would be financed with payments from the Upper Colorado River Basin Fund to divest the lands, structures (including homes), and community infrastructure of the Bureau’s Dutch John, Utah, community that the Secretaries of Agriculture and of the Interior identify as unnecessary. A Bureau official estimated that the agency may incur an additional $300,000 over a 2-year period to administer the transfer of assets.

In a related option, the Congress could authorize the three PMAs to use a portion of their revenues from power sales to directly fund statutorily defined hydropower-related activities of the operating agencies instead of turning the revenues over to the Treasury. The Energy Policy Act of 1992, for example, authorizes Bonneville to directly fund such activities at Bureau and Corps’ hydropower projects in the Pacific Northwest. If the Congress authorizes other PMAs to directly fund hydropower assets of their operating agencies, the PMAs’ access to nonappropriated funds, such as those provided to Bonneville, would be one way to pay for the projects. The Congress, however, may wish to consider limiting the types of projects that may be so funded, as it did for Bonneville.

Change the PMAs’ Power Rates and Repayment Methodologies

Arguments can be made that the way the PMAs establish their revenue requirements and the way they set their rates need to be changed. As noted in our recent products, for example, although generally following applicable laws and regulations, the PMAs’ power rates are not recovering all of the costs associated with generating, transmitting, and marketing federal power. Such cost recovery is generally required by the Reclamation Project Act of 1939 and the Flood Control Act of 1944. DOE’s cost recovery order (Order RA 6120.2), however, excludes certain costs associated with facilities that are not operational and is not specific about the recovery of other costs. The PMAs have consequently interpreted the order to exclude certain costs from their rates. In addition, the nonrepayment of some federal investments in hydropower capacity and other assets (most importantly, irrigation facilities) assigned to power for repayment raises the issue of whether these investments will be recovered under the current repayment methods. In addition, a question arises about whether the PMAs should be required to continue to market their power on the basis of cost-of-service pricing when other parts of the industry are being encouraged to market their wholesale power on a competitive basis.

This section discusses various ways that the PMAs could better recover the costs associated with the federal power program: Increasing PMAs’ power rates.

Charging rates based on competition.

Changing the repayment methodology to recover the federal investment faster and decrease the risk of nonrepayment.

Reallocating costs among the water projects’ multiple purposes.

Merging rate-setting systems to promote the repayment of costs at certain facilities.

Although these changes would address some unrecovered costs that we identified, they would not address all such costs. For example, such unrecovered costs as those associated with the incomplete irrigation facilities at the Pick-Sloan Program, facilities that are not operating because of a lawsuit at the Russell project, or environmental mitigation costs legally exempted from Western’s rates at the Glen Canyon and Shasta dams would not be addressed.

Several of the methods listed could result in rate increases, but decisionmakers should consider that increasing the PMAs’ rates is in the government’s interest only as long as the rates do not rise to the point of being noncompetitive. Because the PMAs already sell power generated at a few of over 100 federal water projects whose power they market at prices at or near the prevailing market price, a rate increase could be counterproductive in these instances and could not be sustained in a competitive marketplace. In addition, some are concerned that rate increases would harm rural communities and customers.

Increase Rates to Better Recover All Costs

Relying on Office of Management and Budget Circular A-25 on user fees as well as industry practices and federal accounting standards, our past reports identified a number of power-related costs that had not yet been fully recovered through the PMAs’ electricity rates. Such costs include those for postretirement health benefits and a portion of Civil Service Retirement System benefits for current employees of the PMAs and the operating agencies, construction costs for some projects that were completed or under construction, and construction and O&M costs for hydropower facilities and water storage reservoirs that are infeasible and therefore not expected to be completed.

Rates could be increased to fully recover some of these costs. For instance, the full costs associated with the postretirement health benefits and the Civil Service Retirement System benefits could be recovered through power rates. The three PMAs will begin the process of recovering pension and postretirement health benefit costs by including the unfunded liability of the Civil Service Retirement System and postretirement health and life insurance costs of power-related employees in their power repayment studies, beginning in fiscal year 1998.

Revenues from rate increases could also pay for unrecovered capital costs for projects that are under construction or not yet in commercial operation when those projects are brought on line. Under DOE’s repayment guidance, the recovery of some federal investments in hydropower has been deferred until projects are completed and placed into commercial operation. These costs are to be repaid when these projects come on line, although rate increases may be substantial. For example, a Southeastern official stated that the costs for the nonoperational pumping units at the Corps’ Russell project, which he estimated at about $528 million as of August 1997, are not yet subject to repayment. Because of litigation over large fish kills, these units have not been allowed to operate commercially and these costs have not been included in Southeastern’s rates. However, if the nonoperational units come on line, these costs would be recovered through rates. The resulting rate increase for customers of that particular rate-setting system may be as high as 25 percent, but in this instance the power would still be competitively priced, according to this official.

Charge Rates Based on Competition

The industry is being encouraged to base its power rates on a competitive basis rather than on cost of service. Therefore, the Congress could enact legislation authorizing or directing the PMAs to change from cost-of-service rates to rates based on competition. In accordance with legislation, the PMAs are to set their rates at the lowest possible level consistent with sound business principles and market their power primarily to preference customers. Because the three PMAs’ overall average revenue per kWh is at least 40 percent below existing market rates, charging market rates for PMA power would most likely cause the PMAs’ rates to rise. With higher rates, the PMAs’ revenue would be likely to increase and, consequently, the risk of nonrepayment of the federal investment would be likely to decrease as long as the rates remain competitive relative to prevailing market rates.

Change the Repayment Methodology to Recover Federal Investment More Quickly

The Congress or the Secretary of Energy could require the methodology for repaying PMA debt to be changed in order to recover the federal investment more quickly. Such a change could increase the PMAs’ rates and revenues as well as the rate of repayment to the Treasury. Under DOE’s current policy and consistent with applicable laws, the PMAs may defer repayment of annual expenses when power revenues do not meet repayment needs during low water years. Deferred annual expenses accrue interest at a current interest rate until they are repaid and generally must be repaid prior to the PMAs’ repaying the principal investment. When repaying principal investment, the PMAs generally must repay their highest interest-bearing debt first rather than the oldest debt. These provisions establish some of the financing flexibility the PMAs need because their revenue reflects the year-to-year variability of water flows and hydropower generation; however, they also result in rates that are lower than they otherwise would be, slower repayment of the federal investment, and a net cost to the Treasury because interest rates on the outstanding federal investment are substantially below the rates Treasury incurs to provide funding to the PMAs and other federal programs. Repaying the federal investment faster would decrease the Treasury’s interest costs and the amount at risk for nonrepayment. However, as for any alternative that increases rates, policymakers would need to consider the impact on the PMAs’ customers and their region.

Reallocate Costs Among the Projects’ Multiple Purposes

The Congress, or in some cases the operating agencies, could revise the formulas used to allocate costs currently assigned to the multiple purposes of the federal water projects or the “joint costs” (those shared among more than one of the purposes—for example, the capital costs associated with the dam). In some cases, this action would reduce the capital investment that would have to be repaid through the rates the PMAs charge for electricity. For example, officials of the Corps and Western’s preference customers noted that some projects currently allocate little or no costs to recreation or water quality, even though these categories have become increasingly important purposes since the operating agencies prepared the project cost allocations. Through reallocation, a portion of the costs assigned to power would be reassigned to recreation and the electric rates could be lowered accordingly.

However, reallocations could result in some costs that are currently being repaid through power revenues—for example, most irrigation-related costs—needing to be repaid through other means. Absent action by the Congress or the operating agencies to institute or increase existing user fees for the activities currently repaid through power revenues, these costs could end up not being repaid. Thus, while the PMAs’ ratepayers could be relieved of the repayment burden of costs no longer assigned to power, the federal taxpayer may end up bearing the burden instead. Also, in commenting on our draft report, DOE’s Power Marketing Liaison Office noted that the equity of certain project beneficiaries (for example, power customers) having to repay more than their fair share of multipurpose costs also needs to be addressed.

In some cases, congressional action would be required to authorize a reallocation of costs. For example, as of September 30, 1994, the federal government had about $454 million in federal investment (1) in the Pick-Sloan Program’s hydropower capacity that was initially designed to be used by future irrigation projects and (2) in the costs associated with storing water for these projects. Although these costs are scheduled to be repaid through Western’s power revenues, under Western’s statutory repayment principles, these costs, which we estimated at $464 million as of September 30, 1996, cannot be recovered unless the associated irrigation projects come into service. According to the Bureau, however, almost all of these planned irrigation projects are infeasible and are unlikely to be completed. Reallocating the $464 million from irrigation to hydropower would help ensure full recovery, but without legislative action to do so, it is probable that Western’s power rates will not recover the principal or any interest on it.

Merge Rate-Setting Systems

For some facilities, rate-setting systems could be merged to expedite repayment. For example, at two facilities—the Stampede Powerplant at the Bureau’s Washoe Project and the Mead-Phoenix Transmission Line, which is partially owned by Western, with a combined federal investment of at least $108 million, as of September 30, 1996—Western generated insufficient income to recover capital and operating costs. Western officials are considering a merger of the Washoe and Mead-Phoenix rates with others, resulting in blended rates and increasing somewhat the likelihood of full repayment of the federal investment.

Restructure the Federal Hydropower Program to Improve Operating Efficiency

In recognition of the changing power markets, the Congress could restructure the PMAs organizationally to better enable them to compete. It can be argued that such changes could provide the PMAs with the flexibility to respond better to market changes and to the needs of their customers, thereby helping to ensure the PMAs’ survival and the repayment of the federal investment. It can also be argued that the PMAs’ federal responsibilities should be continued because of the need to balance the multiple purposes of the water projects. Also, restructuring the PMAs may be seen as an interim step to privatizing them and the operating agencies’ hydropower-related assets.

However, absent congressional action and depending on how the program might be reorganized, any restructuring of the PMAs that increases their operational independence may decrease congressional and other oversight. TVA, a wholly owned federal utility with little external oversight, used its financial ties to the federal government and its operational independence to embark on an ambitious nuclear power building program that resulted in nearly $28 billion in debt, as of September 30, 1996. This debt puts TVA at a competitive disadvantage, especially if the Congress were to revise legislation and require TVA to compete with other power suppliers. TVA’s experience highlights the need for the Congress to carefully consider what oversight would be needed before allowing the PMAs to restructure to be more competitive.

Reorganize the PMAs as Federally Owned Corporations

The Congress could enact laws to authorize the PMAs to operate as federally owned corporations. This type of restructuring, “corporatization,” would allow a government entity that serves a public function of a predominantly business nature to operate in a more efficient, businesslike fashion, while preserving the public service goals that are unique to federal agencies (for example, revenues from Western’s sale of power are scheduled to pay for most of the federal investment in irrigation facilities).

Establishing a PMA as a government corporation has been formally proposed in recent years. In 1994, a proposal was drafted to corporatize Bonneville as a way to help maintain its competitiveness. Bonneville has been faced with competition from alternative power sources with lower costs, debt that exceeded $17 billion as of September 30, 1996, and upward pressure on its costs, caused in part by expanded, more costly efforts to protect salmon. The proposal was based on a recommendation in a National Academy of Public Administration report that examined alternative structures to achieve the maximum efficiency and effectiveness at Bonneville. The administration considered legislation to make Bonneville a wholly owned government corporation under the Government Corporation Control Act. This action was intended to increase Bonneville’s flexibility over personnel; procurement; property management; and budgetary, litigation, and claims settlement functions and to enable Bonneville to compete more effectively in electric power markets. Bonneville estimated that the savings from corporatization would have been as much as $30 million annually. In that the other three PMAs’ operations are much smaller than Bonneville’s, the estimated savings from their corporatization would likely be smaller.

Corporatization may permit repairs and improvements to be financed more expeditiously and predictably than the federal appropriations process. Presuming that a revolving fund would be established as part of the corporatization, the corporation could operate in a businesslike fashion, without having to submit a budget request for annual appropriations to finance operations. Although the electric utility industry is now unbundling its services, depending on how the government corporation was structured, the generation, transmission, and marketing aspects could be put under one agency, possibly reducing overhead. Each PMA could be established as a separate corporation or two or more of the PMAs—Southeastern and Southwestern, for instance, could be merged. The latter option may afford the economies of scale necessary to make the new corporation or corporations viable, according to a Corps headquarters official. Alternatively, distinct federal rate-setting systems could be corporatized as separate entities from the rest of the PMA. Western officials responsible for marketing power from the Bureau’s power plants within the Salt Lake City Integrated Projects—the Colorado River Storage Project plus the Provo River, Falcon-Amistad, and other projects that are aggregated for rate-setting purposes—suggested that their marketing program could be corporatized. They said that it already benefits from substantial operating and budgeting independence because its operations are financed from a revolving fund. However, in its response to our draft report, DOE’s Power Marketing Liaison Office stated that it is not Western’s policy to support the corporatization of this marketing program at this time.

If the government’s objective is to eventually end its participation in a “commercial” activity, corporatization could be an interim step toward divestiture of its hydropower-related assets. In a 1995 report on the privatization or divestiture practices of other nations, we noted that the five nations we reviewed generally (1) converted government agencies or functions into a corporate form before privatizing them or (2) primarily privatized entities already in a corporate form. Converting a government department into a corporate entity, followed in many cases by a privatization, has been common worldwide during the past decade.

In New Zealand, for example, the government included a set of reform principles designed to improve performance in the delivery of public sector goods and services in the State-Owned Enterprises Act of 1986. The government anticipated that entities corporatized under this act would be subject to the same regulation, antitrust, tax, and company law as private enterprise. The restructuring of the electricity industry commenced with the corporatization of the government’s generation and transmission capacity in 1987, corporatization of the retail power companies in 1993, full deregulation of the retail sector in 1993 and 1994, and establishment of a competitive wholesale electricity market in 1996. According to a former New Zealand government official, the government privatized seven small government-owned generating projects in 1995. Additional privatizations of generation facilities, while possible, are not anticipated, according to New Zealand’s Energy and Finance Ministers.

The changes in electricity rates since the New Zealand’s restructuring of the electricity sector are noteworthy, according to a former New Zealand government official we interviewed. Although very large rate increases had been feared for farmers, for example, rural rates declined by about 40 percent in real terms from 1987, when the reform process started, to 1994, according to one study. Cross subsidies between customer classes are reported to be greatly reduced. Over a longer term, inflation-adjusted retail domestic (residential) rates increased by about 5 percent to 15 percent from 1985 through 1997 and from about 16 percent to 20 percent from 1990 through 1997, according to the New Zealand Ministry of Commerce. Commercial rates, on the other hand, decreased by about 20 percent to 28 percent from 1985 through 1997 and by about 1 percent to 9 percent from 1990 through 1997.

In the United States, experience with such conversions after interim corporatization of government activities has been limited. For example, the Congress enacted legislation in 1992 to corporatize DOE’s uranium enrichment operations as the U.S. Enrichment Corporation in a transitional step toward eventual privatization. Similarly, a bill now in House committees would convert the three PMAs into corporations as an interim step toward their privatization.

Despite the advantages, creation of a government corporation could significantly reduce the amount of oversight the entity receives. In the past, we have suggested that the Congress strengthen the oversight and accountability of government corporations. For example, over the years, we and others, have characterized TVA, an existing wholly owned federal corporation, as having insufficient independent oversight. Some have noted, moreover, that an entity that resulted from a merger of, for instance, the Bureau’s water management and power generating responsibilities with Western’s power marketing responsibility could experience conflicts among these three different roles.

Consolidate Power-Related Functions Under One Agency

The Congress could consolidate the power-related operations of the operating agencies and the PMAs. Some operational improvements and cost savings could result. Officials at the Bureau’s Denver office recommended that Western’s assets be returned to the Bureau so that the Bureau could better coordinate the multiple purposes of the water projects, while reducing overhead. They estimate that overhead costs could be reduced by up to 30 percent if Western’s power marketing activities were consolidated within the Bureau.

Although the Bureau and the Corps previously marketed the power they generate, concerns exist about reconsolidating the power marketing function in these agencies because of the need to balance the needs of hydropower with the needs of the other activities the agencies pursue. Each agency has it own priorities, which do not always favor maximizing power revenues. For example, the Congress may provide funds to the Corps to upgrade a failing generator, but if a key lock in the Corps’ navigation system were disabled, the Corps might divert the funds intended for the generator to the lock. This could prolong an outage at the power plant and cause the government to lose revenue. Although a Corps headquarters official stated that this scenario occurred infrequently, he said that a repair project may be deferred because of conflicting priorities. At the same time, if the power generating activities of the Corps and the Bureau were consolidated within the PMAs, the PMAs, which have a primary mission of marketing power, may inadequately consider the other purposes of the water projects when operating the power plants. In addition, consolidations clash with the developing trend among vertically integrated power utilities to segregate generation, transmission, distribution, and ancillary services.

Eliminate Selected Legal and Administrative Requirements

Bureau, Corps, and PMA officials believe that some of the legal and administrative requirements that their agencies must follow cause them to operate in an unbusinesslike fashion and may cause the PMAs’ power rates to increase. For example, aware of the need to operate more efficiently, in February 1996 Western chartered an internal study designed to identify and address laws, regulations, and rules that it determined to be counterproductive to its functioning in a businesslike manner. Although many of the study’s recommendations are administrative in nature, Western identified opportunities to improve its performance that ranged from a few thousand dollars to millions of dollars. For example, the report on the study recommends that Western request an exemption from DOE’s requirement to report quarterly on safety. Western contends the report is of no value, but exempting it from this requirement could save Western $6,630 annually. In another example, Western estimated that if it used a credit card to purchase supplies and services instead of purchase orders, it could save over $500,000 annually. In an example that would require legislative action, exempting Western from the statutory requirements in the Federal Acquisition Regulations about taking sealed bids for procurements could save the agency $115,600 annually. Of more consequence, the Congress could allow Western to pay prevailing local area wages instead of those required by the Service Contract Act of 1965. The report states that such an amendment could save Western about $6.2 million annually. The scope of Western’s study included the Code of Federal Regulations, the Federal Acquisition Regulations, executive orders, DOE’s orders and guidelines, and other directives.

Dispose of High-Cost Hydropower Projects

The Congress could pass legislation that would allow the Bureau and the Corps to divest themselves of projects that have power generating costs that exceed the costs and rates of their rate-setting system. Officials from the Bureau, officials from two of Western’s customer groups, and representatives of some of Southwestern’s customers suggested that the PMAs could operate more efficiently and reduce pressure to raise power rates if the operating agencies were allowed to dispose of several plants that produce higher-cost power. Collectively, they suggested that some of the hydropower plants at the Bureau’s Collbran, Dolores, Loveland Area, and Rio Grande projects as candidates for disposal. According to Bureau officials, some of these projects associated with the Colorado River Storage Project produce power at costs ranging from about 3.5 to 6 cents per kWh, whereas Western sells power at a composite firm rate of about 2 cents per kWh for the Colorado River Storage Project. According to a Corps official, one obvious problem with this option is finding a willing buyer for these inefficient units. Also, to the extent that power revenues cease to pay for some of the federal investment in constructing these units, the taxpayers would assume a larger burden. Whether the government’s investment in these projects is fully recovered depends on the terms and conditions of the sale and the resulting price received for the assets.

Divest the Federal Hydropower Assets

Consistent with the philosophy that the government should not be involved in commercial activities that are best left to the nonfederal or private sector, the Congress could enact legislation to divest the PMAs and the government’s hydropower assets. As we concluded in our March 1997 report, divesting the federal hydropower assets, while possible, would be complicated for several reasons. Any divestiture of hydropower-related assets would need to balance the multiple purposes of the water projects that limit and define how water is released through the turbines, how and when electricity can be generated, and in what quantities. These federal responsibilities would not necessarily terminate after a divestiture. Other factors would also have to be accommodated. These factors include the types of assets being divested, the conditions attached to the sale and the use of the assets after the divestiture, the operating conditions of the assets, the sales mechanism used, and the impact of the divestiture on regional economies, including the impact on regional electricity prices. Of particular note, the impact of a divestiture on the future rates of the preference customers would have to be considered. If the PMAs were privatized, rates would likely increase to varying degrees for most of the current preference customers. Together, these factors complicate the sale of federal hydropower assets and at the same time could affect the willingness of potential buyers to bid on the federal hydropower assets and the price the government could obtain for them. It should be noted that customers themselves have proposed defederalization of the federal hydropower assets. For example, in 1995, 37 of Western’s preference customers advocated an arrangement whereby they would purchase, lease, or obtain other rights to the federal hydropower generating assets within the Boulder Canyon and Parker-Davis projects, as well as certain transmission projects. According to a representative of these customers, this proposal was made to prevent an investor-owned utility from acquiring the federal power resources and was also a reaction against other privatization proposals that were being presented at that time.

Accommodating Multiple Purposes and Other Public Policy Factors

With very few exceptions, federal hydropower projects have multiple purposes specified in their authorizing legislation. For example, the Corps’ Fort Peck project on the Missouri River in Montana has hydropower as a purpose as well as providing for fish and wildlife habitat, flood control, irrigation, navigation, recreation, water quality, and water supply. Multiple purposes are often complementary but are sometimes at odds. For example, water is stored in and released from a reservoir to provide for recreation, but its release through the turbines could be scheduled in a way that is intended to maximize revenue. In contrast, Western’s Billings, Montana, office forecasts decreases in power revenues in the long-term because water, which would otherwise be used to generate electricity, will be increasingly used for irrigation and for other purposes. In its fiscal year 1995 repayment study, Western predicted that revenues from the sale of hydropower would decrease from about $253 million in 2001 to about $213 million (in constant 1995 dollars) in fiscal year 2080 for the Pick-Sloan Program.

At the Bureau’s and the Corps’ water projects, power generation is defined and constrained by the requirement to manage the water for other purposes. The Bureau, for instance, at some projects has restricted releases through the turbines to mitigate environmental impacts downstream. The need to manage water for multiple purposes and to generate hydropower in a way that balances other purposes would have to be accommodated even after a divestiture occurs, absent congressional action.

In addition, the water rights of Native Americans and of states would need to be accommodated in the event of a divestiture. According to Bureau officials, Native Americans’ rights to water at some federal water projects are the earliest and thus supersede the use of water for other purposes, including hydropower generation. As an example, Bureau officials cited a legal settlement with tribal entities of the Fort Peck Reservation in Montana that includes the right to about 1 million acre-feet of water from the Missouri River. In addition, according to DOE’s Power Marketing Liaison Office, a divestiture may have to address how to transfer out of federal ownership the transmission lines and rights-of-way that traverse tribal lands. The tribes may be concerned about the transfer or sale of such lines to private parties.

States also have water rights, and the Bureau and the Corps are increasingly arbitrating between the claims of various states. For example, for several years, Alabama, Florida, and Georgia have been contesting the uses of water in two river basins in the Southeast that the Corps manages.

Regulation of Hydropower Assets Would Be Affected by the Types of Assets Divested

As stated in our March 1997 report, the three general ways the government could divest itself of its hydropower assets are divesting (1) only the PMAs (including the right to market power and any associated federally owned transmission assets); (2) the PMAs and the generating assets of the Bureau or the Corps or both; and (3) the PMAs, the generating assets, and the balance of the projects (for example, the dams and the reservoirs).Divesting combinations of these assets is also possible. In general, divesting only the PMAs and the hydropower generating assets would be less complicated than divesting the balance of the projects because the first two alternatives retain the Bureau and the Corps in their role of managing how water is used and in balancing the projects’ multiple purposes. The kinds of assets divested will influence the regulatory issues accompanying a divestiture.

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, which currently licenses the operation of nonfederal hydropower assets, primarily regulates the reasonableness of wholesale rates charged by the PMAs but does not provide more detailed oversight. According to FERC officials, FERC has experience regulating the multipurpose aspects of water development at over 1,600 projects nationwide pursuant to much the same multiple-use standards as apply to federal projects. FERC, however, does not have complete authority to set regulatory requirements. Other federal and state agencies, through FERC’s regulatory process, may impose mandatory conditions on FERC’s licenses, which complicate FERC’s licensing process.

If only the PMAs (including their rights to sell power and any transmission lines) were divested, then the Bureau and the Corps would continue to operate the hydropower plants, dams, and reservoirs in accordance with existing plans, guidelines, and regulations. In such a case, the buyer would not need a FERC-issued license; the Bureau and the Corps would continue to manage the water as in the past, the existing restrictions would be likely to remain in effect, and the buyer would market the power subject to the same conditions as the former PMA. According to FERC officials, they prefer to license all of a project’s features that have a role in power production.

However, if the power plants were divested as well, the new owner would be required to obtain an operating license from FERC, unless this requirement was specifically exempted by law. Licensing a divested plant could take a long time. We reported, for example, that the median processing time for 111 projects applying for relicensing between January 1982 and May 1992 was 2.5 years. Some had taken as long as 10 to 15 years. In January 1998, a FERC official told us that the median time to relicense over 150 projects whose licenses expired in 1993—the most recent data FERC had analyzed—was about 30 months.

If a divestiture involves a PMA, the power plants, and the balance of the water projects (most importantly, the dams and reservoirs), the Bureau and the Corps would no longer fill the role of specifying the operating conditions of the project. Instead, safeguards for the multiple uses of the water would primarily be contained in the conditions FERC would attach to the operating license pursuant to the Federal Power Act. In such an event, in licensing the hydropower plant, FERC would be required to weigh the plant’s impact on such aspects as the environment and recreation. Licensing would therefore be complicated by the need to complete a number of studies on the power plant’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 have the opportunity to issue a water quality certification.

FERC officials also cautioned that if power plants, dams, and reservoirs were sold, then FERC’s licensing process could revisit the management and uses of the water pursuant to the Federal Power Act and possibly change the operation of the project, potentially affecting power generation. In connection with this issue, the executive director of the National Hydropower Association stated that nonfederal hydropower plants are losing generating capacity because of environmental restrictions or mitigations that are attached as conditions to their operating licenses as FERC relicenses those plants. Moreover, according to a September 1997 report by DOE’s Idaho National Engineering Laboratory, at the time of relicensing, 96 percent of the peaking projects relicensed since 1987 have had their ability to meet peak demand reduced. Of the 52 projects that were relicensed from 1987 to 1996, FERC added capacity to only 4 projects, but the remaining 48 projects had their ability to meet peak demand reduced by from 0.4 to 54.3 percent of their previous capacity: the average reduction was 6 percent. Also, FERC’s review of over 130 projects licensed from the 157 applications filed in 1991 shows that while generating capacity had a very small increase, actual electricity generation had a very small decrease—less than 1 percent.

Trade-Offs Exist Between the Conditions Attached to the Sale and Use of Assets and the Bids Received

The explicit and implicit liabilities borne by the government and which of those liabilities would transfer to a buyer would also affect the price obtained for the federal power assets. Sales of some or all of the hydropower assets—at prices that exceed the value to the government—would produce budgetary savings in the long run, according to a November 1997 report by the Congressional Budget Office. The report estimates that the combined assets of the three PMAs may be worth between about $8 billion and $11 billion. A sale could also result in a future stream of tax payments to the Treasury, also depending on the divestiture’s terms and conditions. However, the report states that losses are possible, depending on the terms and conditions of the sale. In addition, as a matter of general principle, policymakers would need to take into consideration the fact that assets that are sold with many or relatively onerous restrictions (from the viewpoint of a prospective purchaser) or uncertainties about future operations are correspondingly less attractive and are likely to sell for less. 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.

If the government’s objective is to obtain the maximum possible price for its assets, the government could retain certain liabilities that could reduce risks to potential buyers. In some cases, the federal government could be in a better position than the buyer to bear certain risks. For instance, in the proposed divestiture of the U.S. Enrichment Corporation, 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. At some hydropower projects, available generating capacity has been diminished by up to one-third because of the need to mitigate environmental impacts downstream. Buyers may discount any prices they offer because of the loss of available generating capacity unless the government assumes the liability for mitigating environmental impacts. In addition, in the case of the federal hydropower assets, uncertainty about future operating conditions because of potential environmental liabilities may discourage bidding or result in lower prices than if the federal government assumes some of the liabilities. For instance, one provision of the Central Valley Project Improvement Act directs the Secretary of the Interior to manage annually 800,000 acre-feet of water for environmental purposes authorized by the act. According to the Bureau, an analysis of the environmental impacts indicates that hydropower generation may be reduced by about 5 percent. Were the government to divest the project’s assets, it might agree to limit the effect of water use restrictions on potential buyers for a specific period and to specify changes in water use restrictions over time to reduce the uncertainty the buyer would face.

If the government’s objective is to expedite the divestiture on terms that would less adversely affect the projects’ beneficiaries, getting the highest possible price for the assets might be a secondary consideration. For example, although a decision to limit bidders on particular assets to certain geographic areas would foster a goal of local or regional control of those assets and expedite a transfer, it could reduce the proceeds from the sale if other potentially interested buyers were precluded from making offers. In the ongoing divestiture of the Alaska Power Administration, an overriding concern is to protect that PMA’s ratepayers from increases in electricity rates. Decisionmakers therefore restricted the eligibility of bidders to only nonfederal entities from within the state of Alaska. It also accepted a sale 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.

Trade-Offs Between Assets’ Operating Conditions and the Need to Improve Them Must Be Considered in the Event of a Divestiture

Assets that are in better operating condition are more likely to attract higher bids than assets in poor condition. We testified in July 1996 that federal hydropower plants in the Southeast have experienced significant outages and that these outages occur because of the age of the plants—an average of about 30 years—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 lower. 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. DOE’s Power Marketing Liaison Office noted that the statement of the World Bank should not be interpreted to imply that federal facilities should be allowed to decay without proper maintenance.

The Specific Sales Mechanism and Process Need to Be Determined

The objectives underlying a divestiture help determine the most appropriate sales method. For example, if a divestiture is largely motivated by fiscal considerations, an appropriate sales mechanism would involve some form of competitive bidding and tend to place few restrictions on the number or identity of bidders. For example, the Congress, in the 1996 National Defense Authorization Act, directed DOE to sell its Naval Petroleum Reserve No. 1 (Elk Hills) by February 1998 and to do so in a manner that would obtain the maximum proceeds to the government.The government has been producing and selling oil and gas from the field for the past 20 years. According to DOE, the reserve’s sale is part of an effort to remove the federal government from nonfederal functions. In October 1997, DOE announced that it had executed agreements preparing for the reserve’s sale for $3.65 billion in cash as a result of a competition designed to allow all qualified bidders to compete. Before the final selection, DOE had contacted more than 200 companies and received 22 bona fide offers, according to DOE. This sale, which was finalized on February 5, 1998, is the largest divestiture in U.S. government history, according to DOE. In general, we have supported the principle that the federal government should receive full market value in selling its assets.Alternatively, if the major motivation of a divestiture is to transfer operations to the private sector, the government could choose to negotiate a sales price with a selected buyer.

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; trade sales are used more often to sell smaller enterprises or assets and public offerings to sell larger ones. Sales can be organized using competitive bidding methods or negotiations with either type of sale. 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) several bidders are likely 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 assets as well as 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 may be used 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 chose to auction the leases of electromagnetic spectrum licenses for use in mobile communications. While generating a large amount of revenue was a less important objective than achieving an efficient geographic allocation of spectrum licenses to communications firms, the auctions generated more revenue than some potential bidders had predicted, according to auction analysts. In large part, in structuring these auctions, the government carefully considered the auction format and the identification of particular problematic features of auctions of similar assets in other nations.

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 be likely to 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 a prominent law firm with expertise in a variety of fields, including tax and employment law. Also, legislation authorizing the sale of DOE’s Elk Hills Naval Petroleum Reserve required DOE to use an investment adviser to administer the sale.

If the government’s objective is to perpetuate the social and public policy compacts concerning public power, it could transfer or sell its hydropower assets to the preference customers. The assets could be sold free of the debt associated with them. Although such a transaction would provide some revenue to the Treasury, it would probably provide less of a return to the Treasury than a sale to parties that would be willing to pay the highest bid possible for the assets. A debt-free transfer is also harmful to the Treasury because it would incur the debt associated with the hydropower assets, including perhaps any associated debt previously repaid by power revenues—for example, the federal investment in irrigation projects beyond the ability of irrigators to repay. A variation of this suboption is contained in a bill now before House committees. According to the bill’s sponsor, this proposal is designed to avoid the fight over elimination of preference by issuing warrants entitling the existing preference customers to purchase, by a pre-set date and at a stipulated price, a fixed number of shares (based on recent electricity purchases) in the PMA from which they purchase power. The stipulated price would be set somewhat below the expected market price value of the shares. The warrants would be fully negotiable so that the preference customers could sell them if they so chose. The actual sale of the shares would be made to individuals, which could be IOUs or investment bankers, holding the warrants on the specified day of sale.

Impact of a Divestiture on Preference Customers’ Rates Should Be Considered

How a divestiture could affect preference customers’ rates needs to be considered. Some of Southeastern’s, Southwestern’s, and Western’s customers are concerned that a sale would significantly raise their rates. From 1990 through 1995, the three PMAs received less than 2 cents per kWh for their power—at least 40 percent less than what the nonfederal utilities received per kWh during the same period. However, proponents of divestiture contend that competition in the wholesale market would be likely to moderate rate increases. For example, representatives of the Edison Electric Institute (the trade association for IOUs) maintain that because the wholesale market is competitive, very few preference customers will lack access to alternate power suppliers following a divestiture. They believe that, after a PMA is divested, some preference customers who relied heavily on that PMA will be able to purchase power from independent power producers, energy brokers, or energy marketers at competitive rates. In addition, as we noted earlier in this report, many states are moving toward deregulating both wholesale and retail markets.

Representatives of PMAs and their customers believe that having access to alternate supplies of electricity is not enough. They note that even in cases in which 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 areas where 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. In response, Edison Electric Institute officials maintain that preference customers will be able to purchase power even during peak periods at competitive prices.

To address these concerns, we estimated how much preference customers’ rates might increase if the PMAs were divested. We examined only the potential rate impacts of divesting the PMAs and excluded other factors that are currently volatile and difficult to project. In our analysis, we assumed, among other things, that (1) immediately after a divestiture, the buyer of the PMA would raise each preference customer’s rates to the level the customer paid for non-PMA power in 1995 and (2) the preference customers do not change the quantity of electricity they purchased in 1995. Because of a lack of data, we did not assess how increasing competition in the wholesale market may affect the rate changes from divestiture. Also, we did not project whether the emergence of competition in retail markets would affect rates in the wholesale market. It is important to note that our methodology yields conservative results. If prices for wholesale power decline in the future, as many industry analysts believe they will, preference customers’ actual rate changes from divestiture will be smaller than our estimates.

Our analysis shows that most preference customers will experience relatively small rate increases after a divestiture of the PMAs. As shown in figure 3.1, we estimate that more than two-thirds of preference customers may see rate increases of 25 percent or less, or up to 0.5 cents per kWh. If the preference customers passed these costs directly on to their end-users, the average residential end-users’ electricity bills would increase by no more than $4.17 per month. However, we also estimate that some preference customers, mainly those that purchase a large portion of their power from the PMA, may see their rates increase more. About 13 percent of preference customers may see rate increases that exceed 75 percent. Expressed in kWh, about 16 percent of preference customers may see their rates increase by more than 1.5 cents per kWh. If costs are passed directly, the average residential end-users served by about 25 percent of preference customers would see their electricity bills increase by more than $8.33 per month.

Preference customers who currently purchase a small portion of their total power from Southeastern, Southwestern, or Western generally may experience smaller rate increases after a divestiture. For example, in fiscal year 1995, 99 percent of Southeastern’s preference customers received less than a quarter of their power from the PMA. Correspondingly, as illustrated in figure 3.2, we calculated that almost all (98 percent) of Southeastern’s preference customers may experience rate increases of 0.5 cents per kWh or less, and 99 percent would see their rates increase by one-quarter or less. Moreover, we estimated that about 27 percent (or 72) of these customers may see their rates decline if they purchased all of their power at 1995 wholesale market rates. Some of these customers currently may have access to less expensive power; however, for various reasons, these customers have opted not to buy from these sources.

In contrast, preference customers who currently purchase most or all of their power from the PMA may experience much greater rate increases. For example, in 1995, about 38 percent of Western’s preference customers purchased more than half of their electricity from the PMA. As shown in figure 3.3, we estimated that about one-fifth of Western’s customers may see their rates increase by more than 75 percent. About 27 percent of preference customers may see rate increases greater than 1.5 cents per kWh. If preference customers pass the higher rates on to those they serve, the average residential end-users served by about 16 percent of Western’s preference customers may see their electricity bills increase by at least $16.67 per month.

Similarly, almost one-third of Southwestern’s preference customers purchase more than 75 percent of their electricity from the PMA. As shown in figure 3.4, although most of Southwestern’s preference customers will experience relatively small rate changes, about 25 percent may see their rates more than double. If these preference customers pass these increases on to those they serve, the average residential end-users may see their rates increase by at least $16.67 per month.

It is important to remember that, although some preference customers may initially experience significant rate increases, government may mitigate these rate increases through various mechanisms, such as rate caps. In addition, these customers currently pay rates that, on average, are 40 to 50 percent below what neighboring utilities pay that do not have access to PMA power. After the divestiture, these preference customers will be paying the same market rates as those utilities.

Finally, smaller-sized preference customers may experience larger rate increases after divestiture. As illustrated in figure 3.5, we estimated that about one-fifth of Southeastern’s, Southwestern’s, and Western’s small preference customers will experience rate increases exceeding 75 percent. About 30 percent of small customers will see their rates rise by more than 1.5 cents per kWh. In contrast, 2 percent of medium-sized preference customers and 3 percent of large preference customers may see rate increases exceeding 75 percent. However, in all three size categories, a majority of preference customers may experience rate increases of 25 percent or less or 0.5 cents per kWh or less. We believe smaller customers may experience larger rate increases after divestiture because they generally purchase a larger portion of their power from the PMAs than medium-sized and large preference customers.