Federal power marketing administrations (PMAs) are part of the Department of Energy (DOE). The five PMAs sell electric power within 34 states—to all states except those in the Northeast and upper Midwest. They sold about 3 percent of the nation’s electric power output in 1994. Almost all of it is hydroelectric power generated by multiple-purpose dams built and operated by other federal agencies. The Chairman, Subcommittee on Water and Power Resources, House Committee on Resources, and the Ranking Minority Member, House Committee on Resources, asked us to review several issues relating to three of these PMAs—Southeastern, Southwestern, and Western. The primary focus of our review was to determine whether all power-related costs incurred through September 30, 1995, have been recovered through the PMAs’ electricity rates; whether the financing for power-related capital projects is subsidized by the federal government and, if so, to what extent; and how PMAs differ from nonfederal utilities and the impact of these differences on power production costs. In addition, we were asked to provide information on Federal Energy Regulatory Commission (FERC) oversight of the PMAs. Nationwide, there are five PMAs—the three on which this report is focused, plus the Alaska Power Administration and the Bonneville Power Administration. Established between 1937 and 1977, PMAs sell electricity primarily on a wholesale basis with the legislated goal of encouraging widespread use of power at the lowest possible cost to consumers consistent with sound business principles. By law, they are required to give priority in the sale of federal power to public power entities, such as public utility districts, municipalities, and customer-owned cooperatives. These customers are referred to as “preference customers.” PMAs helped make electricity available for the first time to many consumers who lived in rural areas. PMAs generally control and operate power transmission facilities, but do not control or operate the facilities that actually generate electric power. These power generating facilities are controlled by other federal agencies—most often by the Department of the Interior’s Bureau of Reclamation (Bureau) or the Department of the Army Corps of Engineers (Corps). The dams at which the power generating facilities are located also serve a variety of nonpower purposes, including flood control, irrigation, navigation, and recreation. The project must be operated in a way that balances all of these uses—and, in many instances, power is not the primary use. Responsibility for operating the facilities to serve all of these multiple functions rests with the Corps and the Bureau, which are called the “operating agencies.” Unlike most other federal agencies, PMAs are required by law to recover through rates funds appropriated for power-related costs. Funding for the three PMAs is generally through the annual appropriations process. The PMAs receive annual appropriations and make both capital expenditures, such as for PMA-controlled transmission facilities, and operating and maintenance (O&M) expenditures. PMAs generally pay for these expenditures by requesting Treasury to cut checks on their respective appropriation accounts. The operating agencies also receive appropriations. The operating agencies allocate the portions of those appropriations that are used to fund power-related capital and O&M expenses to the PMAs for recovery from power rates. The allocated portion includes all capital costs and O&M expenses that are solely related to the generation of power. In addition, a portion of the operating agency’s “joint costs” are allocated to the PMAs. These are capital costs and O&M expenses related not only to power production but to the dam’s other purposes. The operating agencies allocate the amount of joint costs that are power-related by applying a percentage established for each multiple-purpose project. PMAs recover these appropriations through revenues generated from power sales. The Reclamation Project Act of 1939 and the Flood Control Act of 1944 require PMAs to set power rates at levels that are forecasted as adequate to recover costs. The Reclamation Project Act of 1939 requires that rates for electric power be adequate to recover the power-related share of construction costs, to include interest charged at a rate of not less than 3 percent. The act also requires recovery of annual O&M costs and “other fixed charges as the Secretary deems proper.” The Flood Control Act of 1944 requires that rates for electric power be adequate to recover the cost of “producing and transmitting such electric energy.” Power-related capital costs are to be recovered “over a reasonable period of years.” These legislative provisions have been implemented by the Department of Energy in DOE Order RA 6120.2 (September 20, 1979, as revised on October 1, 1983). This order specifies that the total revenues of any project administered by a PMA must be sufficient to recover O&M costs in the year incurred, to recover federal investment in generation and transmission facilities within a 50-year period, and to recover capital costs allocated to completed Bureau of Reclamation irrigation facilities that are beyond the capability of irrigators to repay (also called “irrigation assistance”). Under the order, capital investments have a longer recovery period than O&M costs. PMAs are generally required to recover, without interest, appropriations used to fund O&M costs in the same year that the expenses are incurred. In contrast, the PMAs are required to recover appropriations that fund capital investments (which we refer to as appropriated debt), with interest, over a specified repayment period. The recovery period is generally 50 years for assets used to generate power and 35 to 45 years for assets used to transmit power. The order specifies that the adequacy of power revenues be tested by the preparation of an annual study, known as a “power system repayment study,” which is submitted by the PMAs for approval to the Secretary of Energy. This study forecasts power-related capital and O&M costs that the PMAs will be required to recover in the future. It also forecasts revenues expected to be forthcoming under current rates. If the study projects that revenues will not be adequate to recover power system costs over the remainder of the repayment period, rates may be increased or other cost recovery actions may be taken. During the year, PMAs generate revenues based on the rates they have established in accordance with the power repayment studies. The three PMAs bill customers for power sales. Southeastern’s and Southwestern’s customers generally make payments directly to a U.S. Department of Treasury “lock box” at a bank. The bank processes the account payments and transfers the cash to Treasury’s General Fund, where it is categorized as miscellaneous receipts. To finance their operations, Southeastern and Southwestern request Treasury to cut checks on their respective appropriations accounts. Western and its customers deposit collections directly to Treasury’s “lock box” or federal reserve bank and then the receipts are posted to various Treasury accounts. Western either seeks annual appropriations from these accounts to finance its operations, or for certain accounts has the legal authority to spend funds without further appropriations. Those Treasury accounts include the Reclamation Fund; Colorado River Dam Fund; Boulder Canyon Project Fund; Falcon and Amistad Operating and Maintenance Fund; Central Valley Project Restoration Fund; Lower Colorado River Basin Development Fund; Upper Colorado River Basin Fund; and Colorado River Basins Power Marketing Fund. In this report, we refer to the recovery from revenues of power-related operating and maintenance appropriations and capital construction costs as a “repayment” or “payment” to Treasury, even though in most cases the PMAs do not write a check or otherwise transfer funds to Treasury. Ideally, over the course of a year, collections received by Treasury will offset, or “repay,” amounts appropriated to the PMAs and operating agencies for O&M expenses, as well as an amortized amount of capital construction costs. The PMAs, pursuant to the DOE Order, monitor expenses and revenues to ensure that power rates are sufficient to generate revenue to recover expenses. The DOE Order prescribes the sequence in which PMAs are to offset expenses with revenues as follows: (1) operations and maintenance, (2) purchased and exchanged power, (3) transmission services, and (4) interest. The remaining revenues are to be applied to the balance due on any payments of annual expenses that have been deferred (these are called “deferred payments,” which the Order requires be repaid with interest) and then toward the repayment of capital investments. The Order also covers other subjects, including priority of capital cost repayment, interest rate calculation, and other PMA ratemaking and accounting criteria. Collectively, Southeastern, Southwestern, and Western Area Power Administrations market power in 30 states. (See figure 1.1.) In fiscal year 1995, they had total power sales of almost $1 billion. The power they sell is produced at 102 power plants built and run primarily by the Corps of Engineers or the Bureau of Reclamation. The three PMAs differ substantially in size and revenue. (See table 1.1.) Western is the largest, accounting for more than four times the revenue of either Southeastern or Southwestern. Southwestern and Western have their own transmission facilities, while Southeastern relies entirely on the transmission services of other utilities. Collectively, the three PMAs are responsible for repaying about $5.4 billion of appropriated debt. (See table 1.2.) For 1995, the weighted average interest rate on this outstanding debt was 4.9 percent. (See chapter 3 for a more detailed discussion of appropriated debt balances and weighted average interest rates.) Additional specific information about each PMA follows. Southeastern. The Southeastern Power Administration was created in 1950 to market federal power on a wholesale basis. The 23 hydroelectric power plants from which Southeastern markets power are all operated by the Corps. About half of the plants (with more than 60 percent of the generating capacity) have been added since 1960. In 1995, Southeastern marketed power to 296 customers. In all, it sold about 6.8 billion kilowatthours (kWh) of energy. The percentage of cost allocated to power by the Corps averages about 69 percent and ranges by facility from about 45 percent to about 81 percent. Because it has no transmission lines of its own, it has no transmission-related investment costs to recover. Southwestern. The Southwestern Power Administration was created in 1943. The 24 hydroelectric power plants from which Southwestern markets wholesale federal power are all operated by the Corps. Slightly less than two-thirds of the plants (and 56 percent of the capacity) have been added since 1960. In 1995, Southwestern marketed power to 95 customers, selling about 7.7 billion kWh of energy. The percentage of cost allocated to power by the Corps averages about 35 percent and ranges by facility from about 21 percent to about 68 percent. Southwestern’s investment in transmission facilities as of September 30, 1995, was about $126 million. Western. The Western Area Power Administration was created in 1977. The establishing legislation transferred power marketing responsibilities and transmission assets previously managed by the Bureau of Reclamation to Western. Western markets power, on a wholesale basis, from 55 hydroelectric power plants. The Bureau operates 45 plants, the Corps operates 6, and the remaining 4 are operated by three other organizations.Western also markets the federal government’s share of electricity generated by the coal-fired Navajo Generating Station in Arizona. In 1995, Western marketed power to 546 customers, selling about 32.8 billion kilowatthours of energy. The percentage of cost allocated to power by the operating agencies for three large projects that Western is responsible for averaged about 50 percent. These three projects accounted for about 83 percent of Western’s 1995 revenues. The individual cost allocations for the three projects were 21 percent, 46 percent, and 84 percent. Western’s investment in transmission facilities as of September 30, 1995, was about $2.1 billion. Each PMA is led by an administrator, who is appointed by the Secretary of Energy. The administrator is authorized to make decisions regarding PMA operations, subject to the supervision and direction of the Secretary. DOE oversight includes approving PMA budgets as part of DOE’s annual federal budget process, establishing each PMA’s personnel limit, and giving interim approval to rate adjustments that the PMA recommends. The PMA financial officers typically participate in the determination of rates. The final approval of PMA rates is the responsibility of FERC. Appendix VI discusses FERC oversight in detail. The Department of Energy’s Office of Inspector General has programmatic oversight responsibility for the PMAs, as well as oversight of the PMAs’ financial accountability. DOE Order RA 6120.2 calls for the PMAs to prepare annual reports containing audited financial statements. The Inspector General retains Independent Public Accountants to perform annual audits of these financial statements. Increasing competition in the wholesale electricity market could have a major impact on the PMAs. Historically, investor-owned utilities (IOUs) and other electricity providers have operated as regulated monopolies. IOUs typically are required to provide electric service to all customers within their power service areas in exchange for exclusive service territories. To serve customers, utilities incur costs for building new generating plants and operating the power system. Through electricity rate charges, IOUs generally recover all costs incurred plus a regulated rate of return. Several key laws have resulted in an increasingly competitive electricity market. The Public Utilities Regulatory Policies Act of 1978 (PURPA) facilitated the creation of small (less than 80 megawatts of capacity) electricity generators that were exempt from many federal and state regulations. Called “nonutility generators” or “independent power producers” (IPPs), these entities typically use new technologies, such as cogenerating plants or natural gas-fired generation units, to generate power. The National Independent Energy Producers estimated that, at the end of 1995, IPPs accounted for about 8 percent of the total generating capacity in the United States. IPPs pose a direct competitive threat to PMAs, IOUs, and other utilities, in part because they can build generation facilities near large industrial or municipal customers and sell power to these customers for a lower rate than the established utility. In addition, recent technological advances have significantly increased the efficiency of natural gas-fired generation units. The growth and increased efficiency of IPPs have placed downward pressure on wholesale electricity rates. The Energy Policy Act of 1992 promoted increased competition in the electricity market. The act encouraged additional wholesale suppliers to enter the market and opened the transmission of electricity by allowing wholesale electricity customers, such as municipal distributors, to purchase electricity from any supplier, even if that power must be transmitted over lines owned by another utility—referred to as wheeling of power. Fees are paid to the transmitting utility for use of its system. Under the act’s provisions, FERC can compel a utility to transmit electricity generated by another utility into its service area for resale. More recently, FERC has issued a final rule implementing this provision of the act. DOE has directed the PMAs to comply with the intent of the act and FERC’s rule. According to Western and Southwestern, they have always operated with a policy of open access to their transmission systems on a first-come, first-served capacity available basis. As a result of the increased competition, FERC expects wholesale and retail electricity rates to drop. Increased competition may impact the PMAs’ status as a low cost supplier. The objectives of this report were to determine (1) whether all power-related costs incurred through September 30, 1995, have been recovered through the PMAs’ electricity rates (chapter 2), (2) whether the financing for power-related capital projects is subsidized by the federal government and, if so, to what extent (chapter 3), and (3) how PMAs differ from nonfederal utilities and the impact of these differences on power production costs (chapter 4). Additional information on our objectives, scope, and methodology is in appendix I. This appendix includes detailed explanations of the calculations of various estimates used in the report, as well as a list of the various organizations and groups we contacted. When appropriate, we used audited numbers from the PMAs’ 1995, 1994, and earlier annual reports. We conducted our review from January 1996 through September 1996 in accordance with generally accepted government auditing standards. We requested written comments on a draft of this report from the three PMAs, the Department of Energy, and the operating agencies. Only the PMAs provided written comments in time for publication in this report. These comments are evaluated and reprinted in appendix II. Some costs related to producing and marketing federal hydropower are not being recovered through power rates by the three PMAs. We identified five main power-related activities for which costs are not fully recovered. First, the three PMAs do not recover the full costs to the federal government of providing Civil Service Retirement System (CSRS) pensions and postretirement health benefits for current PMA employees and operating agency employees engaged in producing and marketing the power sold by the PMAs. Second, there are construction projects for which the three PMAs might not recover costs from power customers. Third, power-related construction and O&M expenses assigned to incomplete irrigation facilities at Pick-Sloan will likely not be recovered. Fourth, certain costs for environmental mitigation have been legislatively precluded from cost recovery. Finally, Western had unrecovered O&M and interest expenses as of September 30, 1995, related to certain projects. Taking into consideration all these categories of unrecovered costs we identified, we estimated that the amount of unrecovered costs for fiscal year 1995 was about $83 million. We estimated that the cumulative amount of these unrecovered costs, as of September 30, 1995, could be as much as $1.8 billion. It is important to note that the PMAs are generally following applicable laws and regulations regarding cost recovery. The Reclamation Project Act of 1939 and the Flood Control Act of 1944, as discussed in chapter 1, generally require the recovery through power rates of the costs of producing and marketing federal hydropower. However, these acts do not specify which costs are to be recovered. The Reclamation Project Act refers to the recovery of “annual operation and maintenance” costs and “other fixed charges as the Secretary deems proper.” The Flood Control Act refers to the recovery of the costs associated with producing and transmitting electricity from federal power projects. Neither act defines its terminology. Recovery of power-related costs has been implemented by the Secretary of Energy through DOE Order RA 6120.2. The DOE order states that all costs of operating and maintaining the power system, as well as the costs of transmission, should be included in rates. The order does not define operating and maintenance costs. Given the flexibility this lack of specific guidance provides, the PMAs have interpreted it to exclude certain costs from rates. To define the full costs associated with producing and marketing federal hydropower, we referred to Office of Management and Budget (OMB) Circular A-25, “User Fees,” which provides guidance for federal agencies to use in setting fees to recover the full costs of providing goods and services. DOE Order RA 6120.2 does not adopt this guidance or otherwise refer to OMB Circular A-25. Nevertheless, the circular does offer a definition of full costs that is useful in identifying power-related costs that the PMAs do not now recover through power rates. OMB Circular A-25 defines full costs as all direct and indirect costs of providing the goods or service. This definition is consistent with that contained in federal accounting standards recommended by the Federal Accounting Standards Advisory Board (FASAB) and adopted by GAO, OMB, and Treasury. The FASAB standards define the full cost of an entity’s output as “. . . the sum of (1) the costs of resources consumed by the segment that directly or indirectly contribute to the output, and (2) the costs of identifiable supporting services provided by other responsibility segments within the reporting entity, and by other reporting entities.” Applying the definitions of “full cost” used in OMB Circular A-25 and federal accounting standards indicates that the full cost of the electricity sold by the PMAs would include all direct and indirect costs incurred by the operating agencies to produce the power, the PMAs to market and transmit the power, and any other agencies to support the operating agencies and PMAs. Investor-owned and publicly-owned utilities generally must recover the full cost of producing power through rates. A discussion of relevant private industry accounting and cost recovery practices is in chapter 4. It is important to note that we did not assess the reasonableness of the methodologies used in developing the operating agency cost allocation formulas that are established for each project. To more fully assess whether PMA electricity rates include all power-related costs would require an analysis of the reasonableness of these allocations. If the allocation formulas were not reasonable, it could result in a substantial over- or under-allocation of costs by the operating agencies to the PMAs. The three PMAs do not recover the full costs to the federal government of providing postretirement health benefits and CSRS pensions for current PMA employees and operating agency employees engaged in producing and marketing the power sold by the PMAs. The employee and the employing agency both contribute annually toward the costs of the future CSRS pension benefits. Since the employee and agency contributions toward CSRS pensions are less than the full cost of providing the pension benefits, the federal government must, in effect, make up the funding shortfall. In addition, neither the agency nor the employee pays the federal government’s portion of postretirement health benefits, which will eventually be paid by the general fund of the Treasury. For 1995 alone, these unrecovered costs for the three PMAs were an estimated $16.4 million. The cumulative unrecovered CSRS pension and postretirement health benefit costs for the three PMAs totaled an estimated $436 million as of September 30, 1995. According to Office of Personnel Management (OPM) officials, pensions for employees covered by the Federal Employees Retirement System (FERS) are fully funded each year and cumulatively, so there are no relevant unrecovered costs. See appendix I for a discussion of our methodology for computing unrecovered pension and postretirement benefit costs. As with all other federal agencies, the full cost of CSRS pension benefits is not paid by the PMAs or the operating agencies. As required, CSRS employees and the agency each pay a fixed percentage—7 percent—of the employee’s salary to offset future pension costs. However, this combined contribution does not cover the full cost of the employee’s future pension benefits, which amounted to more than 25 percent of salary as of September 30, 1995. Thus, the annual funding shortfall is more than 11 percent of every CSRS employee’s salary. The annual funding shortfall associated with pension benefits will be eliminated over time as CSRS employees leave the government and are replaced with FERS employees, provided that FERS pension benefits remain fully funded annually. The full cost of the federal government’s portion of postretirement health benefits (for both CSRS and FERS employees) is likewise not paid by federal agencies, including the PMAs and operating agencies, during the period of the beneficiaries’ employment. OPM estimates that almost $2,000 per employee would need to have been contributed in fiscal year 1995 to cover each employee’s postretirement health benefit costs earned. However, no fund has been established to accumulate assets to pay for these future benefits, which will eventually be paid for by the federal government. In contrast to the situation regarding CSRS pensions, the annual funding shortfall associated with postretirement health benefits will not be eliminated as CSRS employees are replaced by FERS employees, since it is an entirely separate benefit program. OMB Circular A-25 specifically includes all funded or unfunded retirement costs not covered by employee contributions in its definition of full cost. In addition, beginning in fiscal year 1997, Statement of Federal Financial Accounting Standards (SFFAS) no. 5 requires federal agencies to record the full cost of pension and postretirement health benefits in annual financial statements. Private sector accounting standards have required similar reporting for pensions beginning in 1987 and postretirement health and other benefits beginning in 1993. IOUs have adopted SFAS no. 87 and SFAS no. 106 for accounting purposes and in most instances for rate-setting. Based on our analysis of the estimated number of full-time equivalent (FTE) positions involved in producing and marketing the power sold by the three PMAs, and information provided by OPM, we estimated that the fiscal year 1995 unrecovered pension and postretirement health benefits totaled about $10.3 million and $6.1 million, respectively. For pensions, about $7.3 million of the unrecovered costs (70 percent) related to personnel involved in producing and marketing the power sold by Western, while about $1.7 million (16 percent) and $1.4 million (14 percent) related to Southeastern and Southwestern, respectively. For postretirement health benefits, about $4.2 million of the unrecovered costs (69 percent) related to Western, while about $1.1 million (18 percent) and $786,000 (13 percent) related to Southeastern and Southwestern, respectively. These are the amounts that would have been necessary to fully recover CSRS pensions and postretirement health benefits earned in fiscal year 1995 for current employees of the three PMAs and operating agency employees involved in power production and marketing. These costs, which are not recovered by the PMAs through power rates, are shown in figure 2.1. More detailed information regarding these unrecovered costs can be found in appendix III. Based on our analysis of estimated FTEs associated with producing and marketing power and information provided by OPM, we estimated that the cumulative unrecovered costs for pension and postretirement health benefits as of September 30, 1995, are $355 million and $81 million, respectively. For pensions, about $250 million of the cumulative unrecovered costs (70 percent) related to personnel involved in producing and marketing the power sold by Western, while about $57 million (16 percent) and $48 million (14 percent) related to Southeastern and Southwestern, respectively. For postretirement health benefits, about $56 million of the cumulative unrecovered costs (69 percent) related to Western, while about $14 million (18 percent) and $10 million (13 percent) related to Southeastern and Southwestern, respectively. The cumulative unrecovered costs for current employees are depicted in figure 2.2. More detailed information regarding the cumulative unrecovered costs can be found in appendix III. There are construction costs that the three PMAs might not recover from power customers. In two cases, the Richard B. Russell and Harry S. Truman Projects, costs are not currently being recovered because the power-generating projects have not operated as designed. In two other cases, the Washoe and Mead-Phoenix Projects, the tenuous financial condition of the projects raises questions about whether power costs will be recovered. In another case, power-related costs associated with a Western abandoned transmission line incurred before 1969 have not been included in rates and there is a chance that these costs may never be recovered from power customers. To date, about one-half of the cost of constructing the Richard B. Russell Project, which is located on the Savannah River between Georgia and South Carolina, has been excluded from Southeastern’s rates to power customers because the project has never operated as designed. In addition, interest associated with the pumping units is not paid to Treasury each year. Instead, interest—$25.6 million for fiscal year 1995—is capitalized and added to the construction-work-in-progress (CWIP) balance annually. If the project never operates as designed, it is uncertain whether the federal government will be able to fully recover these construction and capitalized interest costs. Positioned between two existing dams, the Russell Project was built virtually exclusively for the generation of hydropower. Ninety-nine percent of the original construction costs and 93 percent of annual O&M expenses associated with the Russell Project are tentatively allocated to power. The project, which enjoyed broad support from electric utilities in North Carolina, South Carolina, and Georgia because of its potential to generate low cost power, was authorized by the Flood Control Act of 1966 and construction began in 1976. The Russell Project has four operational conventional generating units that provide 300,000 kilowatts of capacity, and four nonoperational pumping units intended to provide another 300,000 kilowatts of capacity. The last of the four conventional units came on-line in 1986, and the costs associated with those units went into the customers’ rate base. However, because of litigation over excessive fish kills, the four pumping units, which were completed in 1992, have never been allowed to operate commercially. As a result, the costs associated with them have been left in a CWIP account, where interest has been accruing, and have not been included in rates. Southeastern’s financial statements show about $488 million in CWIP as of September 30, 1995, all of which is for construction costs and capitalized interest related to the Russell Project. Of the $488 million related to Russell, an estimated $338 million was for construction costs and $150 million for capitalized interest. Southeastern continues to classify as CWIP the $488 million of costs related to Russell’s pumping units, even though construction on those units was completed in 1992 and associated litigation and environmental testing have been ongoing since May 1988. According to its fiscal year 1995 financial statements, Southeastern follows SFAS no. 71, Accounting for the Effects of Certain Types of Regulation. In situations similar to Russell’s, if the costs were deemed allowable by the regulator, private entities following SFAS no. 71 would transfer the amount from CWIP to a regulatory asset account and begin recovering costs. Under DOE Order RA 6120.2 guidance, however, Southeastern may not be required to recover the costs of Russell’s pumping units through rates as long as the units are nonoperational. Southeastern officials believe that the litigation over the pumping units will be resolved in Southeastern’s favor, the pumping units will be allowed to operate commercially, and the costs associated with them will be recovered through rates. However, if the four pumping units are never allowed to operate commercially, it is unclear whether the costs associated with them—about $488 million as of September 30, 1995—will be recovered through power rates. A similar situation exists at the Harry S. Truman Dam and Reservoir, which is located in the Osage River in Missouri. Designed originally for flood control, hydropower and recreation were later added as authorized project purposes. Construction of the Truman Project began in October 1964, and it was placed in service (for flood control and recreation) in November 1979. The in-service dates for hydropower generating units range from January 1980 to September 1982. Total power-related construction costs were about $158 million as of the end of fiscal year 1995. The Truman Project has six generating units, also designed to operate as pumping units, which provide 160,000 kilowatts of capacity. However, because of excessive fish kills by the pumping units, the Truman project has never been operated at its 160,000 kilowatt capacity. Instead, only 53,300 kilowatts have been declared to be in commercial operation, and use of the pump-back facilities has never been commercially implemented. As a result, the Corps determined that it would be inappropriate to recover through Southwestern’s power rates the costs associated with the units that have not been used commercially. The Corps prepared an interim cost allocation for this project that accounted for the fact that the project was not fully operational. Southwestern petitioned FERC to have the cost of the nonproducing portion of the assets deferred from inclusion in power rates until it becomes fully operational. FERC concurred as part of its approval of Southwestern’s 1989 power rates. As a result of FERC’s decision, Southwestern has deferred the inclusion of the estimated amount of the costs associated with the nonoperational units in Southwestern’s reimbursable share of the project’s costs. Thus, $31 million, which consists of capital construction costs and capitalized interest, has been deferred from recovery through power rates, reducing the total to be repaid from $158 million to $127 million. This deferral is accomplished through an adjustment to Southwestern’s appropriated debt each year. According to Southwestern officials, the $31 million adjustment is not a permanent elimination of these costs from Southwestern’s appropriated debt; these costs will be included in rates if the Harry S. Truman facility operates as designed. Through 1994 the Corps calculated the interest expense associated with hydroelectric projects related to Southwestern. Interest expense was based on the entire power-related construction costs of these projects. Southwestern was therefore paying interest on the $31 million Truman deferral. Beginning in fiscal year 1995, Southwestern and the other PMAs began calculating the power-related interest expense on the operating agency projects. In 1995, Southwestern’s calculation of interest expense for the Truman project excluded interest associated with the $31 million Truman deferral. About $930,000 in interest associated with the Truman deferral was therefore not paid and was excluded from Southwestern’s rates. Southwestern officials have acknowledged the error and said that the 1995 underpayment of interest will be corrected in fiscal year 1996. The Washoe Project (Stampede Dam) is not generating sufficient revenue to cover annual power-related O&M expenses and interest and repay the federal investment. The 3,650 kilowatt power plant for the Stampede Dam was completed in 1987, and power sales began in 1988. Since the project began producing power, it has only generated sufficient revenue to cover a portion of its annual O&M expenses and has been unable to make any annual interest payments. In addition, the project has not generated enough revenue to repay any of the project’s appropriated debt. Since 1988, the project has deferred about $3.9 million in O&M and interest expense payments. As of September 30, 1995, the outstanding unpaid federal investment in the project was $8.9 million. According to Western, the project has not been able to recover the costs of producing power because the project: (1) has construction costs that are high in relation to other utilities, (2) has not been able to find customers to purchase the power at a rate that would recover the full cost of producing the power, (3) began producing power in the first year of a 7-year drought, and (4) prior to 1992, lacked the transmission service to wheel power to customers interested in buying the power. Western officials project that a permanent rate increase of almost 500 percent would be necessary to recover the annual costs. In January 1996, Western projected that it would have to sell its Washoe power at a rate of at least 11 cents per kilowatthour (kWh) to cover annual O&M expenses (excluding depreciation), interest charges, and debt repayments; however, in fiscal year 1995, the project was selling power at about 2 cents per kilowatthour. According to Western’s fiscal year 1995 annual report: “Based on current conditions, it is unlikely the project will be able to generate sufficient revenues to repay the Federal investment.” For the same reasons, we believe that the Washoe Project is unlikely to generate sufficient revenue to repay all O&M and interest expenses. During fiscal year 1994, Western negotiated a contract to sell some Washoe power to the U.S. Fish and Wildlife Service (F&WS). The project’s authorizing legislation specifies that the cost of facilities for the development of the fish and wildlife resources of the project area, including the O&M costs, shall be nonreimbursable. Western classified the cost of power sold to F&WS as nonreimbursable, thereby reducing the amount of construction and O&M costs that must be repaid to Treasury by the Washoe Project. Western believes the project can become more financially viable by reclassifying a portion of the project’s costs as nonreimbursable. However, we believe this action just shifts the responsibility for recovering the project’s costs from the ratepayers to the federal government, and does not reduce the actual costs of producing the power. Therefore, we believe this action does not significantly improve the prospects of the project being able to generate sufficient revenue to cover all power-related capital costs or O&M and interest expenses. Another project with questionable financial viability is the Mead-Phoenix Transmission Line, a recent addition to the Pacific Northwest-Pacific Southwest Intertie Project intended to increase power transmission capability between the Pacific Northwest and Pacific Southwest. This transmission project was a joint venture between Western and 13 other participants and began operation in April 1996. Western’s share of the total project’s costs is about 34 percent. According to Western officials, Western’s portion of the cost of the project, including capitalized interest, is expected to be about $94.1 million. Western officials said that, in 1990 and 1993, prospective customers of the Mead-Phoenix Line indicated that their demand for power from the line significantly exceeded Western’s proposed share of capacity. However, anticipated demand for power from the line later dropped precipitously, and it is unclear whether Western will be able to successfully market its entire transmission capacity. A Western official told us that during its first few months of operation in 1996, the project has not generated sufficient revenues to cover all O&M and interest expenses. However, Western is confident that sufficient revenues will be raised to recover annual O&M and interest expenses. In recent testimony before the Subcommittee on Water and Power Resources, House Committee on Resources, Western’s Administrator said that it is aggressively marketing the remainder of the line’s capacity. The Administrator indicated that if the project does not achieve the level of sales assumed in developing the transmission charges, Western will initiate a new rate process to ensure the recovery of project costs. If Western is unable to find customers for all of its capacity, it is uncertain whether market forces will allow it to increase its rates enough to generate sufficient revenue to recover annual O&M and interest expenses or appropriated debt. Another example of an unrecovered power-related cost is an abandoned transmission line that has incurred costs of about $14.5 million, which Western has not included in power rates. According to the Bureau, the transmission line, which was planned to be the direct current portion of the Pacific Northwest-Pacific Southwest Intertie Project, was abandoned because of sporadic funding. Because the project has not provided any benefits to project customers, the ratepayers recently requested that Western seek authority through the budget cycle to have about $11.1 million of the cost of the abandoned transmission line declared nonreimbursable. If Western was granted such authority, the power customers would not be required to recover these costs through rates. However, Western recently asserted that it (1) does not plan to request authority to declare any of the costs of this project as nonreimbursable and (2) plans to include the costs of the abandoned transmission line in its power repayment study for recovery. In addition to not repaying the construction costs, Western has not paid the federal government any interest on this investment since construction began on the project in 1965. In fiscal year 1995, if Western had paid interest at the rate that applied when construction began—3 percent—it would have paid about $435,000 in interest on the $14.5 million. We estimate that if Western had begun repaying the annual interest expense on the project costs when construction was discontinued in 1969, it would have paid the federal government about $6.4 million in annual interest payments over the 26-year period from 1969 to 1996. The potential unrecovered costs as of the end of fiscal year 1995 are about $20.9 million. Because the cost of the abandoned transmission line has not been included in rates since construction was discontinued over 26 years ago, we believe doubt exists about whether these costs will ever be included in rates. However, if these costs are ever taken into rates, it is not clear whether interest will be recovered from the time construction was discontinued in 1969 through when the costs are included in rates. It is also unclear whether the 50-year repayment period will begin in 1969 or when the costs are actually included in the power repayment study. In addition, Western did not disclose which rate-setting system would absorb these costs. Western officials were unable to clarify these issues. The cost to the federal government of Western’s decision to delay resolution of cost recovery for the abandoned transmission line will depend on how it decides to address these issues. As of September 30, 1994, about $454 million of the federal investment in the capital costs for hydropower facilities and water storage reservoirs of the Pick-Sloan Missouri Basin Program (Pick-Sloan) had been allocated to authorized irrigation facilities that are incomplete and infeasible. Western is currently selling electricity to its power customers that would have been used by the irrigators had the irrigation facilities been completed. If these costs had been allocated based on the actual use of the hydropower facilities and water storage reservoirs, the costs would have been allocated primarily to power and repaid through electricity rate charges within 50 years, with interest. If all of the irrigation facilities were to be completed as originally planned, the above capital costs would be repaid without interest primarily by power customers. However, since all but one of these irrigation facilities are not expected to be completed, the capital costs assigned to these facilities will not be repaid unless Congress approves a change in the cost allocation methodology used to distribute costs to the various program purposes, or deauthorizes the incomplete irrigation facilities. However, any changes between the program’s power and irrigation purposes may also necessitate reviewing other aspects of the agreements—specifically, the agreements involving areas that accepted permanent flooding from dams in anticipation of the construction of irrigation projects that are now not likely to be constructed. In addition, interest is not being paid on the $454 million. Using the 3 percent interest rate in effect for power projects when construction began, we estimate that lost interest payments to Treasury amounted to about $13.6 million for fiscal year 1995. The federal investment in the Pick-Sloan Program will continue to increase because of renovations and replacements. The capital costs assigned to the incomplete irrigation facilities will also continue to increase because of the cost allocation methodology, which is based on original agreements reached decades ago that anticipated that all irrigation facilities would be completed as planned. For example, in our May 1996 testimony, we noted that the capital costs assigned to irrigation facilities increased about $37 million between fiscal year 1987 and fiscal year 1994, an average annual increase of nearly $5 million. Therefore, unless Congress approves a change in the cost allocation methodology used to assign capital costs to the various program purposes, ongoing power-related capital costs will continue to be assigned to the incomplete irrigation facilities and will likely not be recovered through rates. Annual O&M expenses that otherwise would have been allocated to power and repaid from electricity rates have also been allocated to the incomplete irrigation facilities. Since 1987, Western has adjusted the Corps’ allocated annual O&M expenses because the two agencies interpret specific legislation differently. As of September 30, 1995, about $13.7 million ($15.3 million in constant 1995 dollars) of the Corps’ power-related O&M expenses had been allocated to incomplete irrigation facilities. The annual adjustments have ranged from a low of $1.1 million in fiscal year 1987 to a high of $2.1 million in fiscal year 1995. If these expenses had been allocated to power, they would have been included in Western’s annual O&M expenses and recovered through electricity rates. The Central Valley Project’s Shasta Dam and the Colorado River Storage Project’s Glen Canyon Dam have incurred power-related environmental mitigation costs that are legislatively excluded from Western’s power rates. For the Shasta Dam, these costs totaled $9.7 million and $5.4 million in 1995 and 1994, respectively. For the Glen Canyon Dam, these costs totaled $13.9 million and $12.5 million in 1995 and 1994, respectively. The total cumulative unrecovered environmental costs for the two projects was about $134.3 million ($152.5 million in constant 1995 dollars) as of the end of fiscal year 1995. Certain environmental costs incurred at the Shasta Dam were exempted from recovery by the 1991 Energy and Water Development Appropriations Act. The act included a provision stating that any increase in purchased power cost incurred by Western after January 1, 1986, that resulted from bypass releases for temperature control purposes related to preservation of fisheries in the Sacramento River, not be allocated to power. According to Western, the bypass releases at Shasta will cease when construction of a Temperature Control Device is completed. Western expects this device to be in service by December 1996. Similarly, certain costs of mitigating the environmental impact of fluctuating river flows at the Glen Canyon Dam were exempted from recovery by the Grand Canyon Protection Act of 1992. The purpose of the act was to “protect . . . and improve the values for which Grand Canyon National Park and Glen Canyon National Recreation Area were established.” The act states that certain costs of environmental impact studies related to Glen Canyon Dam are not to be paid for by power customers. The act includes a provision that the above costs could become the responsibility of the power customers under certain circumstances. According to Western, sufficient data does not exist to determine whether the overall provisions of the act would result in a future obligation by the power customers. Western plans to reflect any future obligations related to these costs in the period in which such obligations become evident. Since fiscal year 1975, Western has deferred O&M and/or interest payments on 12 projects that are supposed to be repaid annually. Under DOE Order RA 6120.2, deferred O&M and interest payments are to be repaid the following year, with interest, at DOE policy rates, before repayment of appropriated debt. In effect, the federal government extends an interest bearing loan to the PMAs in the amount of the deferred payments. The balance of Western’s deferred payments outstanding at the end of fiscal year 1995 was about $196 million. This balance decreased from about $250 million at the end of fiscal year 1994 as Western repaid about $54 million in fiscal year 1995. The bulk of the balance outstanding—almost $131 million—was associated with the Pick-Sloan Program. The remaining balance was associated with eight other projects. According to Western, the deferred payments have occurred primarily because of extended drought conditions. As a result of the deferred payments, many of the projects’ firm power rates have been raised by Western. For example, Western stated that the composite firm power rate at the Pick-Sloan Program has increased approximately 75 percent since the start of drought conditions in 1988. Western attributes about half of the increase to the drought and the increased interest expense associated with the deferred payments and the failure to repay outstanding appropriated debt. Although Southeastern and Southwestern have deferred O&M and interest expense payments, both had repaid the amounts, with interest, prior to September 30, 1995. Because of the PMAs’ reliance on hydropower to generate electricity, the PMAs’ annual revenue is unpredictable and varies from year to year. As a result, the DOE order that specifies the terms PMAs must follow to repay their federal investment was designed with the variable revenue characteristics of hydroelectric systems in mind. The DOE order allows the PMAs to vary the repayment of their federal investments and miss interest and/or O&M expense payments in years when revenue is not sufficient to cover these costs. However, the DOE regulations require the PMAs to record deferred annual payments as liabilities on their financial statements and to repay these deferred payments plus interest in future years before any principal payments are made on the outstanding federal investment. The amount and frequency of deferred payments over the last 20 years have varied among the three PMAs. Since fiscal year 1975, Western has deferred either an annual O&M and/or interest expense payment in one or more years for 12 of the 15 projects. As of September 30, 1995, 9 of the 15 projects still had about $196 million in outstanding debt related to deferred payments. Western plans to recover the majority of these costs over time. More detailed information about Western’s deferred payments over the last 20 years can be found in chapter 3 and appendix IV, and a discussion of FERC’s role in rate-setting can be found in appendix VI. According to Southeastern officials, severe drought conditions in the 1980s created poor water conditions and, as a result, insufficient revenue to cover annual interest and O&M payments. Southeastern had also deferred payments in other years due to poor water conditions. Southwestern deferred interest payments in 1977 and O&M and interest payments in 1981. According to Southwestern officials, the payments were deferred primarily because of poor water conditions. Both Southeastern and Southwestern had repaid all their deferred payments as of the end of fiscal year 1995. We estimate that, for the five main power-related activities identified in this chapter, the annual unrecovered costs for the three PMAs is about $83 million for fiscal year 1995. In addition, as of September 30, 1995, we estimate that total cumulative unrecovered power costs could be as much as $1.8 billion. Our analysis of unrecovered power-related costs is shown in table 2.2. In commenting on a draft of this report, the PMAs stated that they agree that there are some power-related costs that were not fully recovered through rates. However, they asserted that the objective of our review was to specifically identify costs that were “unrecoverable,” which they defined as those that have not been and will never be repaid to Treasury under current law and/or policy, as opposed to “unrecovered,” which they defined as those not repaid at a point in time but that will be in the future. While we recognize there is a distinction between the two concepts, we believe that “unrecoverable” costs are essentially a subset of “unrecovered” costs. Moreover, we disagree with the PMAs’ assertion about the objective of our review. The objective, based on our agreements with congressional requester staff, was to determine whether all power-related costs incurred through September 30, 1995, had been recovered through electricity rates. Our objective was not to distinguish between “unrecovered” and “unrecoverable” costs. We have clarified the discussion of our objective in the executive summary and other relevant sections of the final report. In addition, the PMAs disagreed with certain of our characterizations of unrecovered costs in the five main categories discussed in this chapter. These points, and our responses, are discussed below and in appendix II. The PMAs agreed that the full costs of these benefits are not included in PMA power rates. They suggested that we more fully reflect the content of this chapter in our executive summary by noting therein that the cost underrecovery associated with CSRS pensions should go away over time as CSRS employees retire and the federal workforce is comprised of employees covered by FERS, which is fully funded annually. In response, we added an explanatory statement to the executive summary. However, we also note in our executive summary that the unrecovered costs associated with postretirement health benefits will not be eliminated after the shift from CSRS to FERS. In addition, the PMAs believe that they cannot deposit power revenues into the Civil Service Retirement and Disability Fund (Fund) to pay for unfunded retirement benefits, because doing so would violate federal appropriations law by augmenting the annual appropriation made to the Fund. Our objective was not to address whether the PMAs should or should not recover these costs; our objective was to determine whether these costs were unrecovered. Consequently, we did not address whether it would be appropriate for the PMAs to deposit power revenues directly into the Fund to pay for these costs. We agree that should the Congress decide that the PMAs should deposit directly into the Fund an amount to cover these costs, the Congress should enact legislation permitting a transfer of that amount into the Fund. Alternatively, the augmentation issue could be avoided by depositing amounts recovered, like many other PMA ratepayer collections, into the General Fund of the Treasury where the revenue would be available to the Congress to appropriate into the Fund to cover the full cost to the government of CSRS pensions. Recovery of postretirement health benefits could be handled the same way. The PMAs also believe that our reference to OMB Circular A-25 in this chapter was improper, because the PMAs do not recover costs in accordance with the Circular. We agree that the PMAs do not follow Circular A-25, and we note in this chapter that recovery of power-related costs has been implemented through DOE Order RA 6120.2, which does not adopt the guidance in Circular A-25 or otherwise refer to it. We do not state that the PMAs are required to follow Circular A-25; instead, we use the Circular as criteria for defining all the costs associated with producing and marketing federal hydropower. Developing such a definition of full costs was necessary before assessing whether the PMAs were recovering all power-related costs through rates, which was one of the objectives of our review. The PMAs believe that we inappropriately characterized the costs associated with nonoperational projects, specifically Russell and Truman. They assert that we characterized those costs as not only unrecovered but also likely never to be recovered. That assertion is not accurate. Regarding the Russell Project, in our draft report we state that, if the nonoperational pumping units are never allowed to operate commercially, the costs associated with their construction will likely not be recovered. We do not state that it is likely that the units will not be allowed to operate commercially. We only point out the fact that the units have been in CWIP for 20 years and litigation has been ongoing since 1988. We believe these facts demonstrate that the ultimate operation of the Russell pumping units is not a certainty. Moreover, we specifically reiterate Southeastern management’s belief that the pumping units will be allowed to operate commercially and that these costs will be recovered in the future. However, in response to the PMAs’ concerns, we revised the final report to state that it is unclear whether these costs will be recovered if the project never operates to the capacity designed. Regarding the Truman Project, we state that, with FERC’s concurrence, certain costs associated with nonoperational pumping units have been deferred from power rates. We do not state that it is likely that the costs will never be recovered. We merely demonstrate that the ultimate operation of these pumping units is not a certainty. Moreover, we specifically state Southwestern management’s belief that the costs will be recovered if the facilities become operational. The PMAs state that we should incorporate into the report the similarity of Southeastern’s handling of the Russell Project’s cost recovery to similar situations for other utilities governed by FERC and state public utility commissions. As discussed in chapter 4, we agree that FERC and state public utility commissions disallow certain costs and that shareholders of IOUs, not ratepayers, bear these costs. However, we do not believe that Southeastern’s handling of the Russell Project is similar to that of other utilities. Compared to other utilities, the relative dollar amount and the length of time for the deferral of Russell costs from Southeastern’s rates are unique. Note that construction of the Russell Project began in 1976 and the pumping units are still recorded as CWIP today. Thus, Southeastern has not recovered any costs for the nonoperational units. In contrast, IOUs attempt to recover costs immediately, even in situations where the ultimate success of the project is still uncertain. The PMAs state that an abandoned transmission line for Western’s Pacific Northwest-Southwest Intertie Project cannot be declared nonreimbursable or unrecoverable because Western does not have direct legislative authority to do so. As a result, the PMAs assert that Western will include the costs of the abandoned transmission line in rates. This position is contrary to that provided to us during our review. Previously we had not seen any indication that Western planned to include these costs in rates, and all indications were that the costs would be declared nonreimbursable. As stated in this chapter, transmission line construction was discontinued in 1969 and the costs were still included in Western’s financial statements at September 30, 1995. The costs associated with the abandoned line have not been recovered, and no interest has been paid to the Treasury. We estimate that at September 30, 1995, the total unrecovered costs for this abandoned transmission line are about $20.9 million. The PMAs believe that our description of the economic viability of two projects, Washoe and Mead-Phoenix, needs to be clarified. Specifically, the PMAs state that they are reluctant to conclude that projects that are uneconomic today will remain so forever. We agree that project conditions can change over time and that projects experiencing financial problems today, such as Mead-Phoenix, may not face financial problems forever. In addition, we believe that given the increased competition in the wholesale electricity market and wholesale electricity rates that are expected to fall, some projects that are viable today may not be economic in the future. Regarding Washoe, we concur with Western’s assessment in its 1995 annual report that “Based on current conditions it is unlikely the project will be able to generate sufficient revenues to repay the Federal investment.” In addition, we correctly state that the project has been unable to recover all of its O&M and interest expenses and had outstanding deferred payments of $3.9 million as of September 30, 1995. Regarding Mead-Phoenix, we state that a Western official does not expect the project, in its first few months of operation, to generate sufficient revenue to recover all O&M and interest expenses. We believe this fact supports our statement that the project has “questionable financial viability.” The PMAs generally agreed with this section of the chapter, but suggested that we add two points. First, they suggested that more emphasis be placed on the fact that the methodology for cost allocations cannot be changed without congressional approval. We concur with this suggestion and have revised our report accordingly. Second, the PMAs suggested that our report include a statement from our May 1996 testimony that noted that the Pick-Sloan Program incorporates agreements reached decades ago and that any changes to power and irrigation purposes may necessitate reviewing other aspects of the agreements. We have incorporated this statement into our executive summary and chapter 2. The three PMAs receive favorable terms in repaying the appropriated debt that finances capital projects. In addition, the interest rates on outstanding appropriated debt are lower than the cost to the federal government of providing this financing. As a result, a financing subsidy exists because the interest income earned by Treasury on the appropriated debt is less than Treasury’s related interest expense. We estimate that the financing subsidy for the three PMAs for fiscal year 1995 was about $228 million. Cumulatively, this subsidy amounts to several billion dollars. It is important to note that the PMAs were generally following applicable laws and regulations regarding the financing of capital projects. The PMAs have accumulated substantial amounts of appropriated debt at low interest rates. This situation has resulted primarily because the PMAs repay high interest rate debt first and because PMA appropriated debt incurred prior to 1983 was generally at below market interest rates. Historically, a large portion of capital construction projects have been financed with appropriated debt. The three PMAs are responsible for repaying the appropriated debt, which amounted to about $5.4 billion as of September 30, 1995. In addition, as of September 30, 1995, Western was responsible for repaying about $1.5 billion of irrigation-related construction costs (which we refer to as irrigation debt), which is discussed later in this chapter. While the total appropriated debt for the three PMAs has risen over the last 5 years, it has not risen for all of the PMAs. As shown in table 3.1, the appropriated debt balances for Southwestern have declined over the last 5 years. Southeastern’s appropriated debt has remained relatively constant. In contrast, Western’s appropriated debt has increased by $377 million for the same 5-year period. Western’s increase is due primarily to capital spending for new or replacement projects and deferred payments for several projects that resulted in very little or no principal on debt being repaid. Because the power marketed by PMAs is generated at hydroelectric dams, the amount of power available for them to sell is greatly dependent on weather conditions. During years in which precipitation is high, reservoir levels are sufficient to generate large quantities of electricity. In drought years, however, reservoir levels are reduced and there is less electricity generated and available for sale by the PMAs. The Flood Control Act of 1944 provides that appropriated debt must be repaid within “a reasonable period of years,” but it does not specify that any principal on outstanding debt be repaid in any particular year. The Department of Energy’s (DOE) interpretation of this law, Order RA 6120.2, specifies that, unless otherwise prescribed by law, each federal dollar spent on a capital project is to be repaid with interest within 50 years. Shorter repayment periods are used for replacements and transmission facilities. DOE’s Order RA 6120.2 also requires that PMAs, to the extent possible, repay the highest interest bearing appropriated debt first. Appropriated debt carries a fixed interest rate with no ability of Treasury to call the debt. Although PMAs are generally required to pay off highest interest debt first, they cannot refinance the debt. Thus, Treasury bears the risk of increases in interest rates and PMAs, to some degree, bear the risk of decreases in interest rates. Western, for example, has some appropriated debt that is at interest rates above the current Treasury 30-year bond rate. However, because Western cannot refinance this debt and does not have sufficient cash flow to pay it off, it must pay the above-market interest rates. From the inception of the PMAs until 1983, the interest rates paid by PMAs on appropriated debt were either established administratively or by specific legislation authorizing and funding the dam construction. The interest rates specified in legislation were generally 2.5 percent to 3.125 percent. Treasury borrowing rates were based on market conditions. As shown in figure 3.1, when appropriated debt was incurred in the 1950s, the average Treasury interest rate and statutory rates were about the same; however, beginning in the 1960s, the difference between the interest rates paid on the PMAs’ outstanding appropriated debt and the average interest rate Treasury paid on its outstanding bond portfolio in the same years started to grow. Because repayment terms on appropriated debt are up to 50 years, this pre-1983 below market interest debt could remain outstanding for several more decades. By 1985, the average interest rate on Treasury’s outstanding bonds had increased to about 11.02 percent, while the average interest rate on the PMAs’ outstanding appropriated debt was between 2.8 and 3.1 percent. Figure 3.1 also shows the large difference between PMAs in average interest rates on outstanding appropriated debt and the impact of the higher interest rates required after 1983. As of September 30, 1995, Southwestern’s average interest rate on appropriated debt was 2.9 percent, compared to 4.4 percent for Southeastern and 5.5 percent for Western. Southwestern has had strong water years, and its cash flow has allowed repayment of most new appropriated debt, while the low interest debt remains unpaid. According to Southwestern, part of the reason for the strong cash flow is the inclusion in rates of a provision for future capital replacements, which causes rates to be 10 percent higher than necessary to cover current expenses. As of September 30, 1995, only about $45 million of Southwestern’s outstanding appropriated debt of $686 million was financed at interest rates above 3.125 percent. The weighted-average interest rate paid by Southeastern rose from about 2.7 percent in the early 1980s to about 4.4 percent as of September 30, 1995. The increase in average interest rates reflects Southeastern’s inability, due to drought conditions and resulting low revenues, to pay off all the appropriated debt associated with more recent, higher interest rate additions to the power system. In addition, the 6.125 percent interest rate associated with the Russell Project contributed to Southeastern’s average interest rate increase. Western’s average interest rate has risen due to increased market interest appropriated debt resulting from post-1983 construction projects. In addition, according to Western, drought conditions have been the primary reason O&M and interest expenses have been deferred. As a result, Western’s cash flow has not been sufficient to pay off higher interest appropriated debt. The historically low interest rates and flexible repayment terms for PMAs result in a financing subsidy because the interest rates paid by the PMAs do not fully recover the federal government’s cost of funds. (See figure 3.1.) To estimate the financing subsidy, we compared Treasury’s average interest rate on bonds outstanding, which was about 9.1 percent for fiscal year 1995, to the interest rates on the PMAs’ debt as of the end of fiscal year 1995. In this analysis, we used the average interest rate on all Treasury bonds outstanding. The Treasury Bond portfolio includes components with various terms up to 30 years. Since Treasury does not match its borrowing with individual program financing, the average interest rate on Treasury’s entire bond portfolio best reflects its cost of funds. See appendix I for a discussion of our methodology for calculating this financing subsidy. As shown in table 3.2, the estimated financing subsidy using Treasury’s average interest rate on bonds outstanding for fiscal year 1995 was about $228 million. The above estimate shows that Treasury is currently paying a higher interest rate on its outstanding debt than PMAs are paying on their outstanding appropriated debt. Over the next several decades, as the pre-1983 appropriated debt is repaid, the PMAs’ financing subsidy should decrease. However, as shown in figure 3.1, despite new borrowing at market rates, the PMAs’ ability to repay high interest debt first has been a factor and likely will continue to contribute to PMA average interest rates being below the effective Treasury average interest rate. In addition, Treasury’s inflexible borrowing practices contribute to the magnitude of the financing subsidy. Treasury’s general inability to refinance or prepay the federal government’s outstanding debt in times of falling or low interest rates is part of the reason for its relatively high 9.1 percent average cost of funds for fiscal year 1995. We estimate that, cumulatively, the financing subsidy for the three PMAs is several billion dollars. This estimate is based on the spread between Treasury and PMA interest rates shown in figure 3.1, which, to varying degrees, has existed for over 30 years. In 1983, the Department of Energy increased the interest rates at which new projects or replacements to old projects would be financed by modifying its Order RA 6120.2. This modification required that, in the absence of specific legislation to the contrary, new projects, additions, and equipment replacements made after September 30, 1983, be financed at interest rates equal to the average yield during the preceding fiscal year on interest-bearing marketable securities of the United States, which, at the time the computation is made, have terms of 15 years or more remaining to maturity. As shown in figure 3.2, our review showed that, after 1983, new capital projects or replacements that were debt-financed had interest rates that track closely with Treasury rates. The new interest rates did not apply to projects that were already under construction. For example, the Russell project, on which construction started in 1975, continued to capitalize interest at the rate applicable in 1975, 6.125 percent. Projects continue to carry the interest rate in effect at the time the projects are started, regardless of when the borrowing occurred. As a result, Treasury’s cost of funds could either be greater or less than the project rate depending on whether interest rates are falling or rising. In 1985, the year the first electric generating unit became commercially available at the Russell project, the interest cost borne by Treasury was nearly 10.8 percent, significantly higher than the rate of the interest associated with Russell. Since the rates the PMAs pay for new appropriated debt are based on the average of Treasury issues in the prior year, during times of falling interest rates, PMAs will usually pay interest on new appropriated debt at rates above current Treasury rates. Conversely, during times of rising interest rates, PMAs will pay interest on new appropriated debt at rates below current Treasury rates. As shown in figure 3.1, despite new borrowing at market rates, it is the PMAs’ ability to repay high interest debt first that has kept and likely will continue to keep their average interest rates below those of Treasury. However, over time, as the pre-1983 appropriated debt is repaid, the PMAs’ financing subsidy should eventually decrease. In addition to appropriated debt, Western is responsible for repaying certain irrigation-related construction costs on completed irrigation facilities (which we refer to as irrigation debt). As previously noted, reclamation law provides for irrigation assistance to be recovered primarily by power revenues. Although irrigation debt is scheduled to be recovered with power revenues, Western does not view irrigation debt as a PMA cost. Therefore, when Western repays these amounts, neither the costs, nor the related revenues, are reflected in Western’s financial statements. As of September 30, 1995, according to Western, it had approximately $1.5 billion of outstanding irrigation debt, which is to be repaid without interest. The repayment period for the irrigation debt could be up to 60 years after completion of construction—up to a 10-year development period plus a 50-year repayment period. Because DOE’s repayment policies require PMAs to repay their highest interest rate debt first (unless lower interest-bearing debt is at the end of its repayment period, in which case it would be paid first), the irrigation debt, at zero percent interest, will generally not be repaid until the end of its repayment period. As of September 30, 1995, according to Western, about $32 million of the total $1.5 billion of irrigation debt had been recovered through electricity rates. To the extent irrigation debt is repaid through electricity rates, power users are subsidizing irrigators. In addition to the long period allowed for repayment of irrigation debt, completed irrigation facilities were under construction for periods ranging from 1 to 27 years, with an average construction period of about 8 years. Therefore, the irrigation debt may not be repaid, on average, until approximately 68 years after the initial costs were incurred. Using the average interest rate on Treasury bonds outstanding for 1995 of 9.1 percent, we estimate that in 1995 the cost to Treasury of Western’s $1.5 billion of irrigation debt was $137 million. This irrigation debt continues to increase at the Pick-Sloan and other projects due to capital improvements allocated to completed irrigation facilities that are to be repaid by Western. To illustrate the future cost to the federal government of new irrigation debt, we calculated the present value of this new debt, assuming it would be repaid at zero percent interest at the end of the average 68 years that the debt would most likely be outstanding. By applying a discount rate of 7 percent, which approximates Treasury’s current 30-year bond rate, we estimate that the present value of each dollar that will be repaid 68 years from today is less than one penny. In commenting on a draft of this report, the PMAs stated that they agree that certain unpaid investments (appropriated debt) are charged an interest expense that is less than the Treasury’s cost of borrowing at the time the investment was made. However, the PMAs expressed great concern with our methodology for measuring the magnitude of Treasury’s unrecovered financing costs and, as a result, do not concur with our estimate of the magnitude of this cost. The PMAs believe our approach is invalid and is equivalent to assuming that the PMAs refinance their appropriated debt on an annual basis. The PMAs believe that a more accurate methodology for determining the magnitude of the unrecovered financing cost would be to compare each investment’s fixed interest rate against Treasury’s cost of borrowing in the year the investment was placed in service. Thus, they propose calculating the 1995 financing difference by comparing the Treasury’s cost of funds in the year of the PMA investment to the actual PMA interest rate on that investment. As stated in this chapter, we believe that there is a financing subsidy on the PMAs’ appropriated debt because the interest rates the PMAs pay do not fully recover the federal government’s cost of funds. We characterize this situation as a financing subsidy because there is a net cost to the federal government of providing the PMAs with appropriated debt. We do not believe the methodology proposed by the PMAs captures the full amount of this subsidy because it does not consider the impact of the PMAs’ flexible repayment terms or, as discussed below, the impact of Treasury’s borrowing practices. As discussed in appendix I, the methodology described by the PMAs would be a more accurate means to calculate the portion of the subsidy related to the below market financing. However, the records were not available at Western to make the type of specific calculation the PMAs proposed. We calculated the 1995 estimated financing subsidy by taking the difference between the PMAs’ weighted average interest rate for 1995 and the Treasury’s average interest rate on its entire bond portfolio. Since Treasury borrows for the needs of the entire federal government using short-term and long-term financing, and does not match specific borrowings with the PMAs’ appropriated debt financing, the average interest rate on Treasury’s entire bond portfolio best reflects its cost of funds. We believe our approach reasonably captures both the impact of the below market financing provided the PMAs prior to 1983 and the flexible repayment terms currently afforded the PMAs under DOE policies. To help ensure that our methodology was reasonable, we spoke to representatives of OMB, Treasury, and the Congressional Budget Office. The PMAs disagree with our assertion that the Treasury’s additional cost is caused, in part, by the DOE policy of allowing the PMAs to pay off the highest interest rate debt first. The PMAs believe that as long as the interest rate assigned to each PMA borrowing reflects the Treasury’s cost of borrowing at the time, then Treasury is kept whole and no additional cost is incurred. We disagree. Treasury is not “kept whole” because Treasury’s borrowing practices are inflexible in that it is generally unable to refinance or prepay outstanding debt in times of falling interest rates. This inflexibility is part of the reason for Treasury’s relatively high 9.1 percent average cost of funds. Because of the PMAs’ flexibility, and the Treasury’s inflexibility, there are, and likely always will be, differences in the cost of funds. In summary, we continue to believe that the PMAs’ ability to pay off the highest interest rate appropriated debt first, and at any time they desire within the repayment terms of up to 50 years, results in a financing subsidy. PMAs market low cost wholesale electricity. PMAs’ average revenue per kilowatthour (kWh) for wholesale sales has historically been substantially lower than average revenue per kWh for nonfederal utilities. Some of the difference in average revenue per kWh is attributable to the PMAs’ unrecovered power-related costs (see chapter 2) and federally subsidized debt financing. (See chapter 3.) Inherent advantages PMAs have compared to other utilities contribute to lower power production costs and lower average revenue per kWh. One such advantage is that PMAs market primarily low-cost hydropower while other utilities generally must rely on more expensive coal and nuclear plants to generate electricity. Another advantage is that PMAs, as federal agencies, do not, for the most part, pay taxes. PMAs are required to recover several nonpower costs, which is a disadvantage compared to other utilities. Competition in the wholesale electricity market could impact the PMAs’ position as marketers of low cost electricity. As shown in figure 4.1, in 1994 the PMAs’ average revenue per kWh was more than 40 percent lower than IOUs and publicly owned generating utilities (POGs) in the primary North American Electric Reliability Council(NERC) regions in which the PMAs operate. According to the Energy Information Administration, in 1994 the nationwide average revenue per kWh was 3.5 cents for IOUs and 3.9 cents for POGs. The PMAs’ average revenue per kWh in 1994, by rate-setting system, ranged from a low of 0.66 cents per kWh for Southwestern’s Robert D. Willis system to a high of 3.09 cents per kWh for Southeastern’s Georgia-Alabama-South Carolina system. We also reviewed each PMA’s average revenue per kWh compared to national averages for IOUs and POGs from 1990 through 1993. During that period, the PMAs’ average revenue per kWh was consistently at least 40 percent less than those of IOUs and POGs. A detailed comparison of PMA, POG, and IOU average revenue per kWh for 1990 through 1994 and a comparison of each PMA’s average revenue per kWh by rate-setting system to IOUs and POGs in the applicable NERC regions for 1994 is provided in appendix V. We have provided these comparisons by rate-setting system because each PMA system and corresponding NERC region has different average revenue per kWh. These average revenues per kWh may vary considerably by rate-setting system due to customer mix, contractual arrangements, and regional environmental factors such as streamflow and wildlife. In 1994, Southwestern’s average revenue per kWh was the lowest of the three PMAs. The PMAs’ average revenue per kWh, which is generally reflective of power production costs, differs for a number of reasons, such as average interest rates, streamflow, and the operating efficiency of the hydroelectric plants. As discussed in chapter 3, Southwestern has significantly lower average interest rates than the other PMAs. In addition, Southwestern had above average streamflow in 1994 and other recent years. Western, in contrast, has had deferred payments in the 1990s primarily due to drought conditions. A potential reason for higher average revenue per kWh for Southeastern is the operating condition of hydroelectric plants that generate the power that it markets. We recently reported that the Corps’ hydroelectric plants in the Southeast have experienced lengthy outages resulting in declines in reliability and availability of power. We did not review the hydroelectric plants that generate the power marketed by Southwestern and Western to determine if similar operating problems exist. According to the American Public Power Association (APPA), POGs’ average revenue per kWh were higher than IOUs’ average revenue per kWh for several reasons. First, POGs sell a higher percentage of wholesale power under firm power contracts, which command higher prices than nonfirm sales. Second, the timing of many POGs’ construction of coal and nuclear generating facilities, in the late 1970s and early 1980s, coincided with new environmental regulations with which previously built facilities were not required to comply. This is in contrast to many IOUs that built coal plants before the 1970s. Also, POGs often do not have enough of their own generating capacity to meet customer needs and thus purchase power from IOUs. There are some limitations to our comparison of average revenue per kWh. The most recent industry data we could obtain was 1994. Since that time, competition has increased and may have reduced the average revenue per kWh. In addition, we did not include independent power producers (IPPs) in our comparison because similar information was not readily available. IPPs supply a small percentage of the total market (8 percent) with electricity; however, IPPs are providing a large portion of the new capacity with low cost, natural gas-fired turbines, which is driving wholesale electric rates down. IPPs could pose a significant competitive threat to the PMAs. Despite these limitations, we believe that our comparison of the average revenue per kWh is a strong indicator of the relative power production cost and overall competitive position of the PMAs compared to other utilities. Most of the PMAs’ 17 different rate-setting systems appear to be in a strong competitive position compared to POGs and IOUs in their areas. However, several systems have high or increasing production costs. Increasing competition in the utility industry may limit their ability to raise rates. One of these systems, the Washoe Project, is not viable under existing operating conditions. Western is selling electricity from this project for 1.9 cents per kWh that is costing 11 cents per kWh to produce. Other projects, such as Pick-Sloan, face mounting pressure to continue to increase rates. Pick-Sloan had outstanding deferred payments of $131 million as of September 30, 1995. To recover deferred payments and potentially recover irrigation debt, Pick-Sloan faces upward rate pressure. Competition could make it difficult for this project to recover its substantial irrigation debt. Although low cost now, potential rate increases at Pick-Sloan could affect its future competitive position. Another project, the Central Valley Project (CVP), has started to feel the effects of competition and has acted to improve its position. Much of the CVP power that Western sells is purchased from nonfederal sources at prices established in long-term contracts. CVP “passes through” the costs of purchasing this power to its customers; no profit is made. In fiscal year 1995, CVP purchased less power for its customers than in fiscal year 1994 for a variety of reasons. According to CVP officials, one of the reasons for this was that its customers were able to obtain needed power from other sources at a lower price than the price CVP had established in its contracts. CVP officials told us that they expect this trend to continue and have begun to terminate the contracts they hold to purchase power—a process which they expect to continue over the next several years. The rates that CVP charges for firm power are composite; that is, they incorporate the cost of both CVP-purchased and CVP-generated power. CVP’s average revenue per kWh is the highest when compared to other projects where Western markets power. One reason for this is the inclusion in rates of the relatively expensive CVP-purchased power. Since CVP’s repayment study projects the purchase of less and less power in coming years, the consequence could be lower rates. Except for the Georgia-Alabama-South Carolina system, it appears that Southeastern’s rate-setting systems are in a relatively strong competitive position. As discussed in chapter 2, if the inactive portion of the Russell Project is brought on line, according to Southeastern officials, it would likely cause an increase in rates for the Georgia-Alabama-South Carolina system because of the $488 million invested in this portion of the project. As shown in appendix V, the average revenue per kWh at this system—3.09 cents per kWh—is the highest for all three PMAs. Southwestern is in a very strong competitive position in all of its rate-setting systems. As shown in appendix V, there are substantial differences in the average revenue per kWh of Southwestern’s rate-setting systems and the average revenue per kWh of the IOUs and POGs in the NERC regions in which Southwestern markets power. As discussed earlier, the impact of competition in the wholesale electricity market, and the increasing impact of low cost IPP electricity, could affect the PMAs’ competitive position. PMAs sell primarily wholesale power generated at federal water projects. The Flood Control Act of 1944 calls for the PMAs to encourage the most widespread use of electricity at the lowest possible rates to consumers. The PMAs do not sell power for profit. IOUs generally provide a defined service area with power and build new generating capacity to meet future customer needs. Both wholesale and retail electricity is sold by IOUs. The objective of IOUs is to produce a return for their shareholders. POGs are similar to PMAs in that they are owned and/or operated by governmental entities—federal, state, or local. They are nonprofit entities established to serve their communities and nearby consumers at cost. POGs sell both wholesale and retail electricity. Key operating and financial differences exist between PMAs and other utilities. Many of these differences, including the PMAs’ reliance on hydropower, other utilities’ need to pay various taxes, accounting and rate-setting practices, and financing, result in advantages to the PMAs and contribute to the substantial difference in power production costs. In this section, we compare key operating and financial factors of PMAs to IOUs and POGs. We selected two IOUs and two POGs from each of the PMAs’ service areas. In order to be selected, each utility had to generate at least some hydroelectricity. We contacted APPA and the Edison Electric Institute (EEI) to corroborate our findings from the individual utilities. For a description of the methodology for our comparison, see appendix I. PMAs rely almost entirely on hydroelectric power while other utilities are primarily dependent on coal and nuclear generating plants. Table 4.1 shows the large contrast in percent of power coming from various generating sources used by the PMAs and other utilities. According to APPA, POGs on average generated 26 percent of their electricity from hydroelectric plants in 1994. EEI reported that IOUs generated an average of 4 percent of electricity from hydroelectric plants between 1990 and 1994. The hydroelectric plants that generate the power marketed by the PMAs have several key cost advantages over coal and nuclear plants that contribute to lower power production costs, including relatively low capital construction costs and no fuel costs. To show the relatively low capital cost of these hydroelectric plants, we compared the investment in utility plant per megawatt of capacity for these plants to those of other utilities. As shown in figure 4.2, Southeastern, Southwestern, and Western have substantially less invested in power plants than other utilities, which contributes to their lower power production costs. Note that Southeastern’s investment in utility plant per megawatt is substantially higher than the other PMAs. This is because the Russell project, which is discussed in chapter 2, has incurred construction costs of $488 million with no corresponding generating capacity. Compared to other utilities, the lower investment in PMA-related hydroelectric plants is partly the result of construction of these plants 30 to 60 years ago, at lower costs compared to more recent construction. Unlike the PMAs and operating agencies, IOUs build new capacity to meet the future needs of customers. The higher construction costs for the other utilities shown in figure 4.2 reflects more recent construction of coal and nuclear plants. Many IOU and POG nuclear plants that were completed and are operating had significant capital construction costs, which is at least partly due to stringent Nuclear Regulatory Commission (NRC) regulations. Utilities with coal plants must comply with the Clean Air Act, which requires significant investments in pollution control equipment for many plants. The PMAs’ relatively low investment in utility plant results in a large cost advantage. Our analysis excluded nuclear plants that are mothballedand thus provide no capacity while resulting in significant capital costs. Inclusion of these “regulatory assets” would have increased the POG and IOU investment. Appendix I describes the methodology used for computing the ratios in figure 4.2. Another major reason that hydroelectric plants result in lower power production costs is the cost of fuel. This is particularly important when comparing hydro plants to coal plants. The cost of coal is a major operating expense for most other utilities. Nuclear fuel is also a significant cost, although not nearly as large a factor as coal. In 1994, POGs’ fuel costs represented 15 percent of operating revenues, while IOUs’ fuel costs represented 17 percent of operating revenue. The PMAs, on the other hand, have the benefit of marketing power from hydroelectric plants, which do not have an associated fuel cost. The PMAs do have certain costs of operations resulting from hydroelectric production that differ from coal and nuclear generation. According to Southwestern, the Corps is subject to federal regulations, such as the Endangered Species Act and the National Environmental Policy Act. Southwestern, through the Corps’ operations, estimates that it lost about $1.3 million in revenues over the past 5 years through water spilled and operations changed to improve water quality for downstream recreational fisheries. Southwestern also estimates that it has spent nearly $500,000 on equipment, studies, and services in an effort to find solutions to the water quality/sport fisheries problem. Southeastern and Western face similar issues related to the Corps and Bureau operations of their respective hydroelectric facilities. It is important to note here that capital and O&M costs relating to nonpower uses of federal dams, including flood control, navigation, and recreation, are allocated to those other purposes and not included in PMA electricity rates. As discussed in chapter 1, on average, the cost allocations to power are 69 percent, 35 percent, and 50 percent for projects related to Southeastern, Southwestern, and Western, respectively. POGs and IOUs face similar regulations in running hydroelectric dams. The utilities we contacted reported to us that they need to comply with numerous laws including the Federal Power Act, Federal Water Pollution Control Act, Clean Water Act, and the Endangered Species Act. In addition, these utilities are subject to regulations of government agencies such as FERC, the Forest Service, and other state and local governmental agencies. The operations of hydropower projects at the utilities we contacted are greatly affected by these laws and regulations. In fact, several utilities reported to us that the laws and regulations make certain new hydroelectric projects economically infeasible. As with Southwestern, one of the POGs reported that it is required to spill water, which results in over $1 million per year in lost revenues. Some of the utilities reported that they recover a portion of O&M costs for recreational services and facilities; however, for the most part, the capital and O&M costs incurred in complying with laws and regulations are recovered through electricity rate charges. PMAs, as federal entities, are generally not subject to taxes, which gives them a substantial power production cost advantage over POGs and IOUs. POGs, as publicly owned utilities, typically do not pay income taxes because they are a unit of state or local government. However, many POGs do make payments in lieu of taxes to local governments. IOUs are subject to several forms of taxation. Such taxes include all the general taxation rules in the federal tax laws as well as a variety of state and local taxes, such as income tax, gross receipts tax, franchise tax, and property tax. With the exception of the Boulder Canyon Project, the PMAs generally do not make payments in lieu of taxes to state or local governments. The Boulder Canyon Project Adjustment Act of 1940 requires annual payments to the states of Arizona and Nevada. In 1995, the project paid $600,000, or 1.2 percent of operating revenues to these states. According to EEI, in 1994, IOUs, on average, paid taxes totaling about 14 percent of operating revenue. This average varies significantly by state and utility due to differing state and local government taxation laws and various levels of IOU profitability. The IOUs we contacted pay taxes ranging from 11 percent to 20 percent of operating revenue. Examples of taxes paid by the IOUs we contacted are federal and state income tax, real and personal property tax, corporate franchise tax, invested capital tax, and municipal license tax. POGs are exempt from paying federal or state income taxes. However, most POGs we contacted make a contribution to one or more local governmental entities, generally in lieu of property taxes. APPA conducted a survey and found that 77 percent of the respondents made contributions to local governmental entities; 74 percent of those contributions were payments in lieu of taxes. POGs also contribute free or reduced cost electrical service, the use of employees, and other services such as the use of vehicles, equipment, and materials to local governments. A study of 670 public distribution utilities showed that the median net payments and contributions as a percent of electric operating revenue were 5.8 percent. The range of net payments as a percentage of operating revenue for the POGs we contacted varied from 0 to 17 percent. PMAs are agencies of the Department of Energy and thus are required to follow standards recommended by the Federal Accounting Standards Advisory Board (FASAB) and approved by GAO, OMB, and Treasury. Certain FASAB standards directly address accounting requirements for the PMAs. For example, as discussed in chapter 2, SFFAS no. 5 prescribes accounting principles the PMAs will be required to follow for recording the full cost of pension and postretirement health benefits. Because FASAB standards and other relevant federal guidelines do not specifically address regulated entities, the PMAs are allowed to follow the provisions of Statement of Financial Accounting Standards no. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71). The provisions of SFAS no. 71 require, among other things, that the financial statements of a utility reflect the economic effects of rate regulation and provide for a relevant matching of revenues and expenses. Regulatory actions can provide reasonable assurance of the existence of an asset, reduce or eliminate the value of an asset, or impose a liability on the regulated enterprise. For example, if a regulator determined that the costs of a nonproducing power plant were allowable, then the costs of the plant would be carried as a “regulatory asset” and reflected in rates. In contrast, if the costs were determined to be unallowable, the asset would be written off with no corresponding rate charge. IOUs are subject to the pronouncements of FASB and thus prepare financial statements in accordance with SFAS 71. POGs are subject to the pronouncements of the Governmental Accounting Standards Board (GASB). GASB Statement 20, Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities That Use Proprietary Fund Accounting, states that if GASB has not addressed an issue, then an entity may follow FASB guidance. POGs generally prepare financial statements in accordance with SFAS 71 since GASB has not addressed regulatory accounting for governmental entities. IOUs typically use the accrual basis (as modified by SFAS 71) to determine costs to be recovered through electricity rates, using depreciation to recover capital costs. Depreciation as a basis for recovery of capital costs provides a consistent, systematic method on which to base rates by recognizing the cost of the asset equally over its useful life. PMAs and POGs generally use a cash basis or debt service method of setting rates. Under this method, capital costs are recovered through rates as payments for the asset are made. For example, if a capital asset is debt financed, the cost would be included in rates when principal on the debt is repaid or scheduled to be repaid. Repayment terms between PMAs and POGs differ. POGs generally repay principal on debt in fixed annual or semiannual installments, whereas most PMA debt has flexible repayment terms and as such is not required to be repaid until the final year. Rate recovery terms for the various types of utilities vary. Depreciable lives of hydroelectric assets for the IOUs we contacted range from 22 years to 96 years, with most asset types exceeding 40 years. POGs’ tax-exempt bonds are generally repaid over 18 to 40 years. PMAs have 50 years to repay federal appropriations for hydro assets. Therefore, even though the PMAs have flexible repayment terms, in some cases, their costs may ultimately be recovered sooner than the IOUs overall. The financial statements of the PMAs and POGs are presented on an accrual basis in accordance with SFAS 71. The financial reporting difference created by setting rates on a cash basis and reporting on the accrual basis is recognized in the Federal Investment (Equity) section of the PMA financial statements as accumulated net revenues. POGs generally eliminate a mismatch of income between cash basis rate-setting and accrual basis financial statements by recording an asset (liability) on the balance sheet with an offsetting credit (debit) to the income statement. There are differences among IOUs, POGs, and PMAs regarding the types of expenses included in power production costs and resultant rates. The types of expenses included in wholesale and retail rates are subject to approval by utility commissions and may be determined by legislation as well as accounting practices. We found that IOUs typically include all expenses in retail rates unless disallowed by a utility commission. If the utility commission deems that certain expenses do not benefit ratepayers, they will prohibit such expenses from being included in retail rates. For example, one state utility commission decided that advertising expenses, membership dues, lobbying fees, and nonutility operation expenses do not benefit ratepayers and therefore were not allowed to be recovered through retail rates. However, these costs are often recovered fully through wholesale rates because FERC generally allows such costs. An example of costs that FERC may disallow from wholesale rates is a portion of CWIP if FERC determines that the IOU has requested an unreasonable amount to be included in rates. Most POGs we contacted include all of their expenses in rates. PMAs’ rates, on the other hand, do not include some costs, as discussed in chapter 2. However, PMAs are required to recover certain nonpower costs. For example, Western is required to recover the Hoover Dam Visitor Center costs, which are estimated at about $124 million. In addition, Western is required to repay about $1.5 billion of capital costs related to assistance on completed irrigation facilities (irrigation debt). According to FERC, often an IOU will determine within the first 3 years of construction that a project is not viable and halt construction so as to minimize expenses which will not provide benefit to ratepayers. Normally if an IOU halts construction on a project, it will pass these costs through to the ratepayers. A customer may challenge the inclusion of such costs in rates with the appropriate utility commission. The commission may then conduct a prudency test which serves as the basis for allowing such costs in rates. The purpose of the prudency test is to determine whether it was prudent to build the project at the time construction began. If so, then the cost of the abandoned project would be fully included in the rate base. Even if the project does not meet the prudency test, according to FERC, the ratepayers would still be responsible for some portion of the costs and shareholders would be responsible for the remainder of the costs. PMAs are not subject to FERC’s prudency test. PMAs, because of DOE Order RA 6120.2, do not include project costs in rates until put into commercial service. The Russell Project, although not yet operational but determined viable according to Southeastern, was in construction for 16 years and has been awaiting commercial operation for the last 4 years. As such, costs related to the Russell Project totaling $488 million, including accumulated interest, are still in CWIP and excluded from rates. Compared to other utilities, the relative magnitude and length of time for Southeastern’s deferral of Russell from its rates is unique. IOUs’ and POGs’ basic rate-setting methods also differ from PMAs. IOUs and POGs generally use a revenue requirements study. For IOUs, the revenue requirement is the amount of money the utility requires to cover its annual expenses while earning a reasonable rate of return for its investors. POGs follow similar methods but do not require a rate of return since they are publicly owned, although some may include an allowance to provide equity capital for the system. Power repayment studies are prepared annually by the PMAs to determine the adequacy of current rates and determine new rates. The power repayment study tests the adequacy of rates; it entails a 5-year cost evaluation period and recovery of costs within their legally permitted repayment periods. The study also forecasts power-related capital and O&M costs that the PMA will be required to repay in the future and projects future revenues based on current rates. If the study shows that revenues generated under current rates will be inadequate to cover expenses, new rates may be designed. Most of the unrecovered costs identified in chapter 2 are not included in the study and, therefore, are not included in the determination of rates. The methods and costs of capital financing vary greatly among the PMAs, POGs, and IOUs. Federal power-related capital projects rely primarily on debt financing from Treasury. This financing is dependent on the appropriations process, discussed in chapter 1. POGs rely primarily on debt financing from the capital market for capital projects. In addition to debt financing, IOUs are able to use equity financing. PMAs have substantial balances of appropriated debt that have been used to finance the construction of hydroelectric and transmission facilities. As discussed in chapter 3, because of several factors, PMA interest rates on appropriated debt have been subsidized by the federal government. POGs and IOUs also issue debt to finance capital projects. POGs and IOUs typically go to the financial markets to issue various short-term and long-term debt instruments. POGs generally issue bonds that are exempt from federal and state income taxes. This results in POGs getting favorable interest rates on their debt. IOUs issue long-term debt and some short-term instruments, such as commercial paper. IOU interest rates are based on market forces and typically vary based on the bond ratings of the particular IOU. Unlike PMAs, IOUs and POGs have the flexibility to refinance debt in times of falling interest rates. However, as discussed previously, PMAs have the ability to repay higher interest rate debt first, thereby allowing them to effectively manage their debt costs. According to EIA, the average interest rate for 1994 for all POGs was 5.6 percent. For IOUs, it was 7.3 percent. The average interest rates of the POGs and IOUs we contacted for 1995 were in the same range as for the entire industry in 1994. For the POGs, the low was 5.1 percent and the high was 6.1 percent. The IOUs’ range was 6.5 percent to 7.9 percent. In 1995, the PMAs’ average interest rates ranged from 2.9 percent for Southwestern to 5.5 percent for Western. The Bureau has obtained financing for several capital projects from Western’s customers, which we will refer to as “third-party financing.” The Bureau has the authority to accept contributions from Western’s customers to defray the costs of capital construction. As of September 30, 1995, outstanding third-party financing, or customer advances, amounted to about $154 million for the Hoover Dam capital improvement (uprating) program (Boulder Canyon Power System) and about $25 million for the Buffalo Bill project (Pick-Sloan Missouri Basin Power System). The interest rates for the Hoover Dam uprating program range from 5.5 percent to 8.2 percent, and the interest rate for the Buffalo Bill project is 11.07 percent. Under third-party financing arrangements, Western customers provide funding (primarily from the issuance of bonds) to the Bureau to use for the capital project. The customers pay the debt service cost, and Western records the proceeds as a liability and records interest expense. Western then bills the customers for the production costs of electricity, including the debt service on the third-party financing, and credits the customers for the debt service costs. Essentially, this arrangement results in customers directly paying for capital improvements rather than paying for them indirectly through rates. Unlike the Russell Project, which was financed with appropriated debt, third-party financing shifts many of the risks of construction projects to the customers, who are responsible for the bonds, rather than the federal government. In addition to debt financing, federal power-related capital projects are financed using a method similar to revenue financing. Revenue financing is paying for capital projects with net cash generated from operations. Revenue financing for the PMAs occurs when power revenues exceed O&M expenses and the resulting net revenue is used to pay off appropriated debt on new projects or replacements in the first year of the repayment period. In effect, the capital appropriation is repaid in the year that it was made with revenue from current power customers. Southwestern, for example, has been able to keep its average interest rate at 2.9 percent by revenue financing its new projects that would have been financed at DOE policy rates. POGs and IOUs also use revenue financing for capital projects. To the extent a utility is able to finance capital projects from net cash flow rather than debt it will reduce future interest expense. In addition to revenue and debt financing, IOUs have access to equity financing. IOUs are able to issue common and preferred stock and typically pay a large portion of earnings out in common dividends. In 1994 the IOU payout ratio was 80 percent. Dividends represent a financing cost for IOUs. As discussed in chapter 1, PMAs’ appropriated debt generally has terms of 50 years for generating projects and 35 to 45 years for transmission investments. Most of the PMA debt follows a “balloon payment methodology,” in which principal is due at the end of the repayment period with no required annual amortization. This differs from the IOUs we contacted, who reported maximum maturities on debt of 30 to 40 years. IOUs reported that they generally pay principal off in balloon payments at maturity, either through cash flow from operations or refinancing. POGs reported maximum maturities of 18 to 40 years; however, the POGs generally repay principal in fixed amounts each year. As discussed in the rate-setting section, inclusion of capital costs in rates for PMAs and other utilities varies from the cash (debt service) to the accrual basis. We noted several other differences in financing, including control of capital expenditures and placement costs. The PMAs and operating agencies face the constraints of federal budget pressures in obtaining capital financing. According to the Corps, the focus on the federal deficit has put pressure on PMA and operating agency budgets and has resulted in less funding for PMAs and operating agencies for hydropower capital programs. POGs and IOUs have more direct control over capital budgets. However, POGs and IOUs are thus subject to the scrutiny of the market, such as the bond rating system, which affects the appeal of the bonds to the investing public. IOU financing is also subject to the scrutiny of regulators. The PMAs, as federal agencies who are appropriated capital funds, do not pay any placement costs or transaction fees. In contrast, POGs and IOUs must pay placement costs. The POGs and IOUs we contacted reported placement costs from .09 percent of the face value of the debt offering up to 1.5 percent. In addition, IOUs reported placement costs on common and preferred equity offerings of about 3 percent. When compared to IOUs, PMAs and POGs are generally more highly leveraged. Figure 4.3 shows that the PMAs and POGs rely heavily on debt financing for capital projects. The PMAs’ and POGs’ ratios of long-term debt as a percentage of total assets are much higher than IOUs because PMAs and POGs finance most of their capital expenditures with debt rather than equity or revenue. IOUs may utilize a combination of debt, equity, and revenue financing which results in lower leverage. However, IOUs’ also pay dividends to stockholders which are, in essence, a financing cost. This cost is not a factor in the calculation of interest on long-term debt to operating revenue in figure 4.3. If IOUs’ common dividends were included in this calculation, then an average of 15 percent of IOUs’ operating revenue would be paid for financing costs. There is an expected correlation between long-term debt to total assets and interest on long-term debt to operating revenue for each of the entities. Those utilities that utilize debt to a greater extent to finance capital expenditures have greater interest expense relative to operating revenue. The PMA ratio of interest on long-term debt to operating revenue would be much higher if interest rates were not subsidized by the federal government, as discussed in chapter 3. The ratio shown for Southeastern is higher than the other PMAs because of the Russell Project, which is incurring capitalized interest but generating no revenue. Southwestern’s ratio is only 18 percent because of its low average interest rate of 2.9 percent. In commenting on a draft of this report, the PMAs stated that they are not truly comparable to other utilities because they have unique characteristics that make certain comparisons against other utilities of limited value. The PMAs stated, for example, that unlike “traditional utilities,” they do not have a responsibility to meet load growth in their regions or the authority to acquire new firm power resources. The PMAs stated that it is inappropriate to compare their hydropower costs to coal and nuclear generation of other utilities. We agree with the PMAs that they are different from other utilities in the ways discussed in this chapter, including cost of production, types of generating facilities, payment of taxes, accounting and rate-setting, and financing. We also discuss in this chapter the different missions and responsibilities of PMAs, IOUs, and POGs. We believe that power customers are primarily concerned with production costs and resultant electricity rates, not whether the supplier is an IOU, POG, or PMA or whether the supplier is using coal, nuclear, or hydroelectric generation. Given increasing competition and electricity rates that are expected to fall, if the PMAs do not remain low-cost suppliers, then they may not be able to recover all power-related costs. Therefore, our discussion of the differences in power production costs between PMAs, IOUs, and POGs and the reasons for these differences is essential. The PMAs agreed with our statement in this chapter that PMAs are low-cost suppliers of electricity. However, the PMAs are concerned that our use of average revenue per kilowatthour (kWh) is overly simplistic and may mislead readers about the magnitude and causes of differences in costs between PMAs and other utilities. The PMAs do not believe average revenue per kWh takes into account differences in types of electricity sold that result in different prices. They believe a more accurate measure would be to compare similar products being offered by different utilities. The PMAs appear to be concurring with the results of our analysis but disagreeing with the methodology that led to those results. We continue to believe that the average revenue per kWh is a strong indicator of the relative power production costs of the PMAs as compared to IOUs and POGs. For PMAs and POGs, over time, average revenue per kWh should equal cost because each operates as a nonprofit organization that recovers costs through revenues. For IOUs, average revenue per kWh should represent cost plus the regulated rate of return. Given that a large portion of IOU rate of return (net income), 80 percent, is used to pay common stock dividends, which is a financing cost, average revenue per kWh also approximates power production costs for IOUs. We acknowledge in appendix I that we did not perform a detailed electricity rate comparison of PMAs to nonfederal utilities. We also state in this chapter that the price that any one utility charges another for wholesale energy comprises numerous factors. We believe that the PMAs’ alternative methodology of comparing similar products being offered would provide a reasonable rate or price comparison. However, as the PMAs note in their comments, this analysis would be difficult, and the PMAs themselves have not done it. Also, the PMAs’ proposed analysis would not necessarily result in a better indicator of relative production costs because different types of power may be sold above or below total production cost. Average revenue per kWh, on the other hand, better captures total production costs. The PMAs also stated that a related problem with using average revenue per kWh as a measure of the PMAs’ competitiveness is the variability in output of PMA hydropower projects. The PMAs believe our use of average revenue per kWh to indicate competitiveness could result in wide variations in a PMA’s competitive position from year to year. In order to address this factor, we reviewed the PMAs’ average revenue per kWh for 1990 through 1994. For each of these years, the PMAs’ average revenue per kWh was consistently at least 40 percent less than those of IOUs and POGs. We believe that this 5-year comparison is a strong indicator of the PMAs’ current competitiveness. The PMAs also expressed concern that the report gives greater focus to advantages enjoyed by the PMAs without giving equal attention to other costs that the PMAs’ customers must repay that would not normally be charged to nonfederal utility customers. The PMAs stated that we report that irrigation assistance is a large subsidy paid by Western’s customers and suggested that we also note other examples, such as future replacement costs, the Hoover Dam Visitor Center, payments in lieu of taxes, and billions of irrigation investments that are not even in service. We believe that our report provides an appropriate discussion of the relative advantages and disadvantages the PMAs have compared to nonfederal utilities. However, we believe the advantages outweigh the disadvantages. The PMAs’ use of hydropower plants built 30 to 60 years ago, tax-exempt status, unrecovered costs discussed in chapter 2, and the financing subsidy discussed in chapter 3, in aggregate, provide the PMAs with a substantial cost advantage compared to nonfederal utilities. We believe this large difference is reflected in the average revenue per kWh comparisons shown in this chapter and appendix V. We agree that the PMAs have disadvantages compared to nonfederal utilities, and we have more fully reflected those in this chapter. For example, we added the Hoover Dam Visitor Center as a nonpower cost that Western must recover through rates. However, we do not agree with the PMAs’ statement that our draft report said that irrigation assistance is a large subsidy paid by Western’s customers. Our draft report stated that “as of September 30, 1995, according to Western, about $32 million of the total $1.5 billion of total irrigation debt has been recovered through electricity rates.” To the extent that Western actually repays this irrigation debt, the power users are subsidizing irrigators. The billions of future irrigation investments that are not even in service are not costs that have been incurred, and it is questionable whether they ever will be incurred. To the extent that these planned future costs are included in Western’s power repayment studies and impact current rates, the actual application of any relevant power revenue would be to other appropriated debt. We believe that until these future irrigation costs are incurred and repaid, or funds are set aside for their future repayment, they do not represent a disadvantage to Western. The PMAs stated that Southwestern’s inclusion of future replacement costs in its current repayment study results in its rates being 10 to 15 percent greater than they would otherwise be. We do not agree with this statement. The actual application of the revenues generated by inclusion of these costs in current rates has been to current year capital appropriations or other appropriated debt. As a result, Southwestern has been able to pay off most of its recent, higher interest debt and currently has a weighted average interest rate of 2.9 percent compared to 4.4 percent for Southeastern and 5.5 percent for Western. In addition, as discussed in chapter 3, Southwestern has reduced its balance of appropriated debt from $769 million at September 30, 1991, to $686 million at September 30, 1995. Thus, we believe that Southwestern has managed its appropriated debt using sound business principles and has minimized its interest expense that must be recovered through rates. Another disadvantage cited by the PMAs relates to tentative project cost allocations. The PMAs stated that the tentative cost allocations may very well be higher, as in the case of the Clarence Cannon Project, than the final allocated costs. According to Southwestern’s 1995 annual report, there are four projects that still have tentative allocations. Southwestern states in this report that “he amount of adjustments that may be necessary when final allocations are approved for these projects is not presently determinable.” Because final allocations can either increase or decrease the percentage of costs allocated to power, the net effect of changes to allocations will not be known until all are finalized. Therefore, we do not believe that these tentative allocations represent a disadvantage to the PMAs.

Summary: Pursuant to a congressional request, GAO reviewed three power marketing administrations' (PMA) cost recovery practices, and financing for capital projects, focusing on how these PMA differ from nonfederal utilities. GAO found that: (1) the three PMA are not recovering through power rates some costs related to producing and marketing federal hydropower; (2) PMA are not recovering the full costs of providing postretirement health benefits and Civil Service Retirement System pensions to agency employees; (3) the Western Area Power Administration will probably not be able to recover the construction costs of its Washoe Project because it is not generating sufficient revenue to cover its operating and maintenance expenses and repay the federal investment; (4) Western is not required to repay the $454 million allocated to its incomplete irrigation facilities; (5) PMA rely primarily on debt financing for their large capital construction projects; and (6) compared to other nonfederal utilities, PMA benefit from their reliance on inexpensive hydropower, lower construction costs, and tax-exempt status.