    Federal Electricity Activities: The Federal Government's Net Cost and
    Potential for Future Losses (Letter Report, 09/19/97,
    GAO/AIMD-97-110,AIMD-97-110A).

    Pursuant to a congressional request, GAO reviewed federal electricity
    activities, focusing on the: (1) federal government's net recurring cost
    from the electricity-related activities at the Department of
    Agriculture's Rural Utilities Service (RUS), the Department of Energy's
    power marketing administrations (PMA), and the Tennessee Valley
    Authority (TVA) for fiscal year (FY) 1996 and, where possible, the
    cumulative net cost for FY 1992 through 1996; and (2) likelihood of
    future losses beyond the net recurring costs to the federal government
    from these entities.

    GAO noted that: (1) the federal government incurs net costs of over a
    billion dollars annually in supporting the electricity-related
    activities of RUS and the PMAs; (2) GAO estimates that the net costs to
    the federal government for FY 1996 totaled about $2.5 billion--$0.4
    billion for BPA, $0.2 billion for the three PMAs, and about $1.9 billion
    for RUS, including about $982 million in RUS loan write-offs; (3) the
    federal government is exposed to additional future losses beyond the
    recurring net costs resulting from the government's more than $84
    billion in direct and indirect financial involvement in the
    electricity-related activities of RUS, the PMAs, and TVA as of September
    30, 1996; (4) these potential future losses relate to the possibility
    that RUS borrowers, the PMAs, and TVA would be unable to repay the full
    $53 billion in debt owed to the federal government or that the federal
    government would incur unreimbursed costs as a result of actions it took
    to prevent default or breach of contract on the $31 billion in
    nonfederal debt; (5) this risk exists because certain RUS borrowers, the
    PMAs (to varying degrees) and TVA are financially vulnerable primarily
    as a result of uneconomical construction projects and the accumulation
    of substantial debt, which have resulted in high fixed costs; (6) the
    Southeastern, Southwestern, and Western PMAs generally market wholesale
    power that consistently costs at least 40 percent less than power sold
    by nonfederal utilities and are therefore currently competitively sound
    overall; (7) however, the three PMAs maintain this overall soundness in
    part because they do not recover all power-related costs; (8) if they
    were required to recover some or all of these power-related costs, their
    ability to remain competitive might be impaired and the risk of future
    financial loss to the federal government increased; (9) also, each has
    one or a few projects or rate-setting systems with problems that, taken
    as a whole, make the risk of some loss to the federal government
    probable; and (10) for TVA, the risk that the federal government will
    incur losses is remote as long as TVA retains a position similar to a
    traditional regulated utility monopoly in its service area.

    --------------------------- Indexing Terms -----------------------------

     REPORTNUM:  AIMD-97-110
                 AIMD-97-110A
         TITLE:  Federal Electricity Activities: The Federal Government's
                 Net Cost and Potential for Future Losses
          DATE:  09/19/97
       SUBJECT:  Electric utilities
                 Loan repayments
                 Federal corporations
                 Utility rates
                 Cost analysis
                 Competition
                 Losses
                 Intergovernmental fiscal relations
                 Financial analysis
                 Energy marketing

    ******************************************************************
    ** This file contains an ASCII representation of the text of a  **
    ** GAO report.  Delineations within the text indicating chapter **
    ** titles, headings, and bullets are preserved.  Major          **
    ** divisions and subdivisions of the text, such as Chapters,    **
    ** Sections, and Appendixes, are identified by double and       **
    ** single lines.  The numbers on the right end of these lines   **
    ** indicate the position of each of the subsections in the      **
    ** document outline.  These numbers do NOT correspond with the  **
    ** page numbers of the printed product.                         **
    **                                                              **
    ** No attempt has been made to display graphic images, although **
    ** figure captions are reproduced.  Tables are included, but    **
    ** may not resemble those in the printed version.               **
    **                                                              **
    ** Please see the PDF (Portable Document Format) file, when     **
    ** available, for a complete electronic file of the printed     **
    ** document's contents.                                         **
    **                                                              **
    ** A printed copy of this report may be obtained from the GAO   **
    ** Document Distribution Center.  For further details, please   **
    ** send an e-mail message to:                                   **
    **                                                              **
    **                                            **
    **                                                              **
    ** with the message 'info' in the body.                         **
    ******************************************************************

    Cover
    ================================================================ COVER

    Report to Congressional Requesters

    September 1997

    FEDERAL ELECTRICITY ACTIVITIES -
    APPENDIXES TO THE FEDERAL
    GOVERNMENT'S NET COST AND
    POTENTIAL FOR FUTURE LOSSES

    VOLUME 2

    GAO/AIMD-97-110A

    Federal Electricity Activities

    (913805)

    Abbreviations
    =============================================================== ABBREV

      AEAN - aggregate entry age normal
      APPA - American Public Power Association
      ASCC - Alaska Systems Coordinating Council
      BPA - Bonneville Power Administration
      CBO - Congressional Budget Office
      CFTE - contractor full-time equivalent
      CWIP - construction work-in-progress
      CSRS - Civil Service Retirement System
      CVP - Central Valley Project
      CVPIA - Central Valley Project Improvement Act
      DOE - Department of Energy
      DOJ - Department of Justice
      ECAR - East Central Area Reliability Coordination Agreement
      EIA - Energy Information Administration
      EPAct - Energy Policy Act of 1992
      ERCOT - Electric Reliability Council of Texas
      FCRPS - Federal Columbia River Power System
      FERC - Federal Energy Regulatory Commission
      FERS - Federal Employee Retirement System
      FFB - Federal Financing Bank
      FTE - full-time equivalent
      GAAP - generally accepted accounting principles
      G&T - generation and transmission
      IOU - investor-owned utility
      IPP - independent power producer
      kWh - kilowatthour
      KPMG - KPMG Peat Marwick
      MAAC - Mid-Atlantic Area Council
      MAIN - Mid-America Interconnected Network
      MAPP - Mid-Continent Area Power Pool
      MOA - memorandum of agreement
      NERC - North American Electric Reliability Council
      NPCC - Northeast Power Coordinating Council
      NRC - Nuclear Regulatory Commission
      OMB - Office of Management and Budget
      OPM - Office of Personnel Management
      O&M - operations and maintenance
      PMA - power marketing administration
      POG - publicly owned generating utility
      PP&E - property, plant and equipment
      PURPA - Public Utilities Regulatory Policies Act of 1978
      RDA - Rural Development Administration
      REA - Rural Electrification Administration
      RUS - Rural Utilities Service
      SERC - Southeastern Electric Reliability Council
      SEPA - Southeastern Power Administration
      SFAS - Statement of Financial Accounting Standards
      SFFAS - Statement of Federal Financial Accounting Standards
      SPP - Southwest Power Pool
      SWPA - Southwestern Power Administration
      TVA - Tennessee Valley Authority
      UKW - Urbach Kahn & Werlin
      USDA - United States Department of Agriculture
      WAPA - Western Area Power Administration
      WPPSS - Washington Public Power Supply System
      WSCC - Western Systems Coordinating Council

    PREFACE
    ============================================================ Chapter 0

    This volume provides the appendixes to our report, Federal
    Electricity Activities:  The Federal Government's Net Cost and
    Potential for Future Losses, Volume 1.  It contains background
    information on the federal entities included in our review:  the
    Department of Agriculture's Rural Utilities Service (RUS); four power
    marketing administrations of the Department of Energy--the
    Southeastern Power Administration, the Southwestern Power
    Administration, the Western Area Power Administration, and the
    Bonneville Power Administration; and the Tennessee Valley Authority.
    This volume also (1) contains a detailed explanation of our
    objectives, scope, and methodology in carrying out this review, (2)
    provides additional information on the likelihood of future losses to
    the federal government from the electricity-related activities of
    these entities, and (3) provides further details on the federal
    government's net costs related to these activities.  The 14
    appendixes in this volume are organized as follows:

      -- Appendix I contains background information on the entities and
         the status of deregulation and competition in the electric power
         industry.

      -- Appendix II contains our objectives, scope, and methodology.

      -- Appendix III provides information on our use of average revenue
         per kilowatthour to assess competitiveness.

      -- Appendix IV provides further details on the entities' net costs.

      -- Appendix V provides additional information on RUS' financing
         costs.

      -- Appendixes VI through IX provide additional information on the
         likelihood that the federal government will incur future losses
         due to these entities.

      -- Appendixes X through XIII contain the written comments on a
         draft of this report from each of these entities.

      -- Appendix XIV lists the major contributors to this report.

    If you have any questions concerning this review, please call me at
    (202) 512-8341 or Gregory D.  Kutz, Associate Director,
    Governmentwide Audits, at (202) 512-9505.

    Linda M.  Calbom
    Director, Civil Audits

    BACKGROUND
    =========================================================== Appendix I

    The electricity industry is changing in response to the regulatory
    environment and the advent of competition.  As discussed in volume 1
    and the related appendixes in this volume, the federal government
    will be affected by these changes because of its involvement in the
    electric power industry.  Several federal government entities are
    directly or indirectly involved in electricity generation,
    transmission, and distribution.  They include the Rural Utilities
    Service, the five federal power marketing administrations, and the
    Tennessee Valley Authority.\1

    --------------------
    \1 Additionally, many of the federal hydroelectric dams that generate
    power were built and are operated by the Corps of Engineers or the
    Bureau of Reclamation.  Other federal players involved in electricity
    generation, transmission, and distribution include the Bureau of
    Indian Affairs under the Department of the Interior and the
    International Boundary and Water Commission under the State
    Department.

       LEGISLATIVE CHANGES CREATE A
       COMPETITIVE ELECTRICITY MARKET
    --------------------------------------------------------- Appendix I:1

    Historically, investor-owned utilities (IOUs) and other electricity
    providers have operated as regulated monopolies.  Under traditional
    utility regulations, IOUs were generally required to provide electric
    service to all customers within their power service area, and their
    rates were regulated by state public utility commissions.  In
    exchange, they received exclusive service areas.  To serve their
    customers, IOUs could incur costs for building new generating plants
    and operating the power system.  Regulators generally allowed rates
    to be set to guarantee IOUs full recovery of their prudently incurred
    costs plus a regulated profit or rate of return.

    However, the electric utility industry has been in the process of
    transformation, with moves toward deregulation and competition being
    major factors in this transformation.  Deregulation will impact the
    industry's three major segments:  generation, dealing with the
    production of electricity; transmission, involving moving bulk
    electricity from the generation plant; and distribution, the process
    of delivering the power to the retail consumer.  An electric utility
    usually controls all three segments within its service area.

    The generation segment has been affected by improvements in
    technology, which have reduced both the cost of generating
    electricity as well as the size of generating facilities.  Prior
    preference for large-scale--often nuclear or coal-fired--power plants
    has been supplanted by a preference for small-scale production
    facilities, such as cogenerating plants\2

    or small natural-gas-fired generation units, that can be brought
    on-line more quickly and cheaply, with fewer regulatory impediments.
    According to 1994 studies of utility best practices, primary actions
    taken by utilities to satisfy demand are either adding small
    gas-fired combustion units or purchasing power.\3 These sources are
    less capital intensive and more flexible resources for satisfying
    changing demand.  Gas-fired plants can be built in relatively small
    megawatt increments (for example, 50-150 megawatts), at perhaps
    one-quarter of the cost of larger power plants.  In 1995, almost half
    of all new generating capacity starting commercial operation was
    gas-fired, 99 percent of which was either gas turbine or combined
    cycle units.

    The generation segment of the industry has further been affected by
    changes in legislation.  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 state and federal regulations.  Called "nonutility generators"
    or "independent power producers" (IPPs),\4 these entities typically
    use the newer technologies to generate power.  The creation of IPPs
    and their use of newer technologies have lowered the entry barriers
    to electricity generation and permitted IPPs to build profitable
    facilities.  IPPs may pose a threat to more traditional utilities
    because they can build generation facilities near large industrial or
    municipal customers and generally may be able to generate power at a
    lower cost than the established utility.  The Electric Power Supply
    Association\5 estimated that at the end of 1995, IPPs accounted for
    about 9 to 10 percent of the total generating capacity in the United
    States, directly competing with utility-owned capacity and placing
    downward pressures on electricity rates.

    The transmission segment of the industry has also undergone major
    changes due to legislative changes.  The Energy Policy Act of 1992
    (EPAct) promoted increased wholesale competition 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.  This transmission
    of electricity across transmission lines of another utility is
    referred to as wheeling of power.  Under the act's provisions, the
    Federal Energy Regulatory Commission (FERC)\6 can generally compel a
    utility to transmit (wheel) electricity generated by another utility
    into its service area for resale.  Fees, which are regulated by FERC,
    are paid to the transmitting utility for the use of its transmission
    system.

    On April 24, 1996, FERC issued Orders 888 and 889 to implement EPAct.
    FERC Order 888 was key to the growth of wholesale (sales for resale)
    competition because it provided a framework under which such
    competition could flourish.  In issuing its final rules, FERC
    concluded that the rules would "remedy undue discrimination in
    transmission services in interstate commerce and provide an orderly
    and fair transition to competitive bulk power markets." At the time
    the rules were issued, FERC estimated that the rules would result in
    an annual cost savings of $3.8 billion to $5.4 billion.  FERC also
    expected other nonquantifiable benefits, including better use of
    existing institutions and assets, new market mechanisms, technical
    innovation, and less rate distortion.

    As a result of PURPA and EPAct, and as provided for under FERC 888,
    wholesale competition is becoming a reality today throughout the
    country.\7 As a result, many IOUs have set up power marketing arms
    (power marketers and power brokers)\8 that are buying and selling
    excess power across the country.  According to industry sources, the
    number of power marketers registered in the United States increased
    from 60 to 284 from January 1995 to February 1997--an increase of
    over 370 percent.

    With the advent of wholesale competition, pressure is growing to open
    the distribution segment of the industry to allow retail competition
    as well as to allow generating companies or utilities to sell
    directly to final customers in the franchise area of a different
    utility while paying regulated rates to use the utilities' existing
    transmission and distribution lines.  Just as wholesale wheeling
    under EPAct opened competitors' transmission systems for wholesale
    competition, retail competition would require open access to a
    competitor's distribution system for the purpose of selling power to
    individual retail customers.

    Retail competition is taking shape on a state-by-state basis.
    California became one of three states in 1996 to pass laws
    deregulating electric utilities.  Beginning January 1, 1998, all of
    California's retail customers will be able to choose their
    electricity suppliers.  This change not only affects California's
    current electricity suppliers, but also opens the door for other
    companies hoping to sell power to California consumers.  Regulatory
    commissions in 44 states and the District of Columbia had adopted or
    were evaluating deregulation alternatives as of June 30, 1996.
    Issues relating to retail wheeling are also being addressed by the
    Congress.

    In many industries, competition has been shown to result in lower
    costs.  In the airline industry, we reported that average fare per
    passenger mile was between 8 percent and 11 percent lower in 1994
    than in 1979, while the overall quality of air service at airports
    has increased.\9 As early as 1986, one study found that increased
    competition arising from airline deregulation has resulted in a
    savings for travelers of at least $6 billion annually in reduced
    fares.\10 In the first 10 years after the telecommunications industry
    was restructured, prices for long distance telephone services dropped
    by 66 percent, while over the same period prices for regulated local
    telephone service rose 13 percent.  Similarly, since the natural gas
    industry was restructured during the 1980s, prices for industrial gas
    users dropped 52 percent, and residential rates dropped 10 percent
    (although most residential customers still buy gas from regulated
    local distribution companies).\11 Savings in the gas industry have
    been placed at $90 billion over the last 10 years.\12

    --------------------
    \2 The cogeneration of power involves the use of steam, waste heat,
    or resultant energy from a commercial or industrial plant or process
    for generating electricity.

    \3 1994 Electric Utility Outlook, Washington International Energy
    Group (Washington, D.C., January 1994) and Issues and Trends Briefing
    Paper:  18 Key Trends Affecting the Electric Utility Industry, Edison
    Electric Institute (Washington, D.C., May 1994).

    \4 IPPs are not considered utilities because they do not produce
    power for a service area and do not engage in transmitting or
    distributing power.

    \5 The Electric Power Supply Association is a trade association
    representing many nonutility generators of electricity and IPPs.

    \6 FERC is an independent agency within the Department of Energy with
    broad regulatory authority over the interstate transmission and sale
    of wholesale electricity, natural gas, and oil.

    \7 TVA, for the most part, is exempt from the wheeling provisions of
    the Energy Policy Act of 1992 and therefore does not have to allow
    competitors to use its transmission lines to sell power to TVA's
    customers.  This allows TVA's service area to remain insulated from
    wholesale competition.

    \8 Power marketers take title to electric energy before resale.
    Power brokers, on the other hand, do not take title and are limited
    to matching buyers with sellers.

    \9 Airline Deregulation:  Changes in Airfares, Service, and Safety at
    Small, Medium-Sized, and Large Communities (GAO/RCED-96-79, April
    1996).

    \10 Steven Morrison and Clifford Winston, The Economic Effects of
    Airline Deregulation, (Washington, DC.:  The Brookings, 1986).

    \11 "The Case for Retail Wheeling." Energy, Volume XX, Issue 5,
    (1995), pp.  9-12.  This article was excerpted from Peter C.
    Christensen, Retail Wheeling:  A Guide for End-users, (Tulsa,
    Oklahoma:  Penn Well Publishing Co., 1995).

    \12 Patrick Crow, "Electric Restructuring," Oil & Gas Journal, Vol.
    95, Issue 11 (March 17, 1997), p.  32.

          STRANDED COSTS
    ------------------------------------------------------- Appendix I:1.1

    In deregulating the electricity industry, several key issues need to
    be resolved, including who will pay for stranded costs.  Although
    definitions vary, stranded costs cannot be recovered through rates
    even though the utilities incurred those costs to serve their
    customers with the understanding that regulatory commissions would
    allow the costs to be recovered through electric rates.  For example,
    a utility may have built facilities or entered into long-term fuel or
    purchased power supply contracts with the reasonable expectation that
    its customers would renew their contracts and would pay their share
    of long-term investments and other incurred costs.  Accordingly, if
    the customer obtains another power supplier or is no longer willing
    to pay the full costs incurred to provide a service, the utility may
    be unable to recover those costs and thus would have stranded costs.
    Estimates of the U.S.  industry's total stranded costs range from $10
    billion to $500 billion, with $135 billion commonly cited as a
    reasonable estimate.  Although stranded costs are one of the most
    contentious issues associated with deregulation, FERC has determined
    that at the wholesale level, stranded costs should be paid by
    electric customers desiring to exit a system built to serve them.

    The following sections provide additional background information on
    the federal entities involved in electricity generation,
    transmission, and distribution that are discussed in this report.

       THE RURAL UTILITIES SERVICE
    --------------------------------------------------------- Appendix I:2

    The U.S.  Department of Agriculture (USDA) is the federal
    government's principal provider of loans used to assist the nation's
    rural areas in developing their utility infrastructure.  Through the
    Rural Utilities Service (RUS), USDA finances the construction,
    improvement, and repair of electrical, telecommunications, and water
    and waste disposal systems.  RUS provides credit assistance through
    direct loans and through repayment guarantees on loans made by other
    lenders.  Established by the Federal Crop Insurance Reform and the
    Department of Agriculture Reorganization Act of 1994, RUS administers
    the electricity and telecommunications programs that were operated by
    the former Rural Electrification Administration (REA) and the water
    and waste disposal programs that were operated by the former Rural
    Development Administration (RDA).  In this report we will only
    discuss the electricity segment of RUS' overall utility loan
    program.\13

    Although operating somewhat like a commercial lender for rural
    utilities, RUS is not required or intended to recover all of its
    financing or other costs.  RUS' primary function is to provide credit
    assistance to aid in rural development.  Interest charges to its
    borrowers cover only a portion of the federal government's cost for
    RUS' electricity loan programs.

    --------------------
    \13 The Rural Electrification Act of 1936, as amended (7 U.S.C.  901
    et seq.), provides the basic statutory authority for the electricity
    and telecommunications programs, including the authority for loans to
    be made by the Federal Financing Bank.

          RUS' ELECTRICITY LOAN
          PROGRAMS
    ------------------------------------------------------- Appendix I:2.1

    RUS makes direct loans primarily to construct and maintain
    electricity distribution facilities that provide electricity to rural
    users.  RUS makes direct loans at below-market interest rates
    according to law.  For these loans, it receives annual appropriations
    to cover the interest differential.  It also receives an
    appropriation to cover its administrative expenses.  Loans from the
    Federal Financing Bank (FFB) are made at Treasury's cost of money
    plus one-eighth of 1 percent.

    RUS electricity loans are made primarily to rural electric
    cooperatives; more than 99 percent of the borrowers with electricity
    loans are nonprofit cooperatives.  These cooperatives are either
    Generation and Transmission (G&T) cooperatives or distribution
    cooperatives.  A G&T cooperative is a nonprofit rural electric system
    whose chief function is to sell electric power on a wholesale basis
    to its owners, who consist of distribution cooperatives and other G&T
    cooperatives.  A distribution cooperative sells the electricity it
    buys from a G&T cooperative to its owners, the retail customers.  RUS
    has 55 G&T borrowers (see figure I.1) and 782 distribution borrowers
    located throughout the country with outstanding electricity loans.

       Figure I.1:  RUS G&T Borrowers

       (See figure in printed
       edition.)

    Note:  These RUS borrower identification codes designate the
    respective locations of the 55 RUS G&T borrowers' headquarters.

    Source:  GAO analysis of data provided by RUS.

    Some RUS loans are at below market interest rates.  The following are
    the types of loans provided in the electricity program:

      -- Hardship rate loans:  Direct loans with a 5 percent interest
         rate.  These loans, referred to as hardship rate loans, are made
         to borrowers that serve financially distressed rural areas.

      -- Municipal rate loans:  Direct loans with interest rates that are
         tied to an index of municipal borrowing rates.  These loans have
         a maximum interest rate of 7 percent when the borrower meets, at
         the time of loan approval, either a consumer density test or
         both an electricity rate disparity test and a consumer income
         test.  If these tests are not met, the interest rate may exceed
         7 percent.

    Consumer density test:  The borrower's total electric system has to
    have an average of less than 5.5 consumers per mile of line.

    Rate disparity test:  The borrower's average revenue per kilowatthour
    sold has to be more than the average revenue per kilowatthour sold by
    all electric utilities in the state in which the borrower provides
    service.

    Consumer income test:  Either the average per capita income of the
    residents receiving electric service from the borrower has to be less
    than the average per capita income of residents of the state in which
    the borrower provides service or the median household income of the
    households receiving electric service from the borrower has to be
    less than the median household income of the households in the state.

      -- Direct FFB lending:  RUS is required to make 100 percent loan
         repayment guarantees for any loans made to rural utility
         borrowers through FFB.  FFB loans have an interest rate that is
         the Treasury's cost of money plus one-eighth of 1 percent.

    In addition to providing direct loans, RUS also guarantees repayment
    of loans for rural utilities made by commercial banks--RUS guarantees
    100 percent of loans from qualified lenders.  However, RUS has not
    guaranteed any loans from commercial banks in recent years because
    all applicants have applied for loans made by the FFB, which offers
    Treasury's interest rate plus one-eighth of 1 percent.

          RUS' LOAN OBLIGATIONS
    ------------------------------------------------------- Appendix I:2.2

    At September 30, 1996, RUS' portfolio included about $32.3 billion in
    electricity-related loans and guarantees.\14 Most of the dollar
    amount of the portfolio is made up of loans to the G&T cooperatives.
    The principal outstanding on these G&T loans is approximately $22.5
    billion, which is about 70 percent of the RUS electric loan
    portfolio.  Distribution borrowers make up the remaining 30 percent
    of the electricity portfolio.

    For a further discussion of RUS' financing and debt, see our report
    entitled, Rural Development:  Financial Condition of the Rural
    Utilities Service's Loan Portfolio (GAO/RCED-97-82, April 11, 1997)
    and appendixes V and VI of this report.

    --------------------
    \14 Collectively, RUS has a portfolio of $42.5 billion in outstanding
    principal for utility loans including electricity,
    telecommunications, and water and waste disposal.

       POWER MARKETING ADMINISTRATIONS
    --------------------------------------------------------- Appendix I:3

    The federal government owns and operates numerous multipurpose dams,
    many of which generate electric power.  The power generated at these
    facilities is marketed through five federal entities called power
    marketing administrations (PMAs).  The PMAs' mission is to market
    power generated at federal hydroelectric dams at the lowest possible
    rates to consumers, consistent with sound business principles.  By
    law, PMAs 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."

    The five PMAs--Southeastern Power Administration (Southeastern),
    Southwestern Power Administration (Southwestern), Western Area Power
    Administration (Western), Alaska Power Administration, and Bonneville
    Power Administration (BPA)--are part of the Department of Energy
    (DOE).  Since the Alaska Power Administration is being sold to
    nonfederal entities, it is excluded from our analysis in this report.
    Additionally, throughout this report, we frequently discuss BPA
    separately from the other three PMAs because its revenue is more than
    twice as large as the other three PMAs combined and because it faces
    different operating risks.

    PMAs generally control and operate power transmission facilities\15
    but do not control or operate the facilities (dams) that actually
    generate electric power.  These power generating facilities were
    built and are operated by other federal agencies--most often by the
    Department of the Interior's Bureau of Reclamation (Bureau) or the
    U.S.  Army Corps of Engineers (Corps).  These agencies are referred
    to as the operating agencies.  The operating agencies constructed
    these facilities as part of a larger effort in developing
    multipurpose water projects that have functions other than power
    generation, including flood control, irrigation, navigation, and
    recreation.  The projects must be operated in a way that balances
    their authorized purposes--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 operating agencies.

    PMAs sell electric power within 34 states--to all states except those
    in the Northeast and upper Midwest (see figure I.2).\16 Each PMA has
    its own specific geographic boundaries and system of projects from
    which power is marketed.

       Figure I.2:  Service Areas for
       Southeastern, Southwestern,
       Western, and BPA

       (See figure in printed
       edition.)

    Source:  GAO analysis of data provided by the PMAs.

    --------------------
    \15 Southeastern has no transmission facilities.

    \16 In addition to the areas shown on the map, the Alaska Power
    Administration markets power in Alaska.

          ROLE OF SOUTHEASTERN,
          SOUTHWESTERN, AND WESTERN
    ------------------------------------------------------- Appendix I:3.1

    Collectively, Southeastern, Southwestern, and Western sell power
    produced at 102 facilities and market it in 30 states (see figure
    I.2).  In fiscal year 1995, they had total power revenue of almost $1
    billion.  The three PMAs differ substantially in size and revenue.
    Western is the largest, accounting for more than 4 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.  Additional
    specific information about the three PMAs is shown in table I.1.

                                        Table I.1

                              Information on the Three PMAs

                                                                 Revenue
                           Number of                kWh sold         (in
                          hydroelect   Number of  (billions)   millions)    Miles of
                    Year  ric plants   customers      fiscal      fiscal  transmissi
                 created  Sept. 1995  Sept. 1995   year 1995   year 1995    on lines
    ----------  --------  ----------  ----------  ----------  ----------  ----------
    Southeaste      1950          23         296         6.8        $159        none
     rn
    Southweste      1943          24          95         7.7         114       1,380
     rn
    Western       1977\a          55         546        32.8         713      16,760
    ================================================================================
    Total                        102         937        47.3        $986      18,140
    --------------------------------------------------------------------------------
    \a In 1977, the DOE Organization Act established the Western Area
    Power Administration and transferred power marketing responsibilities
    and transmission assets previously managed by the Bureau of
    Reclamation to Western.  The act also transferred the other PMAs from
    the Department of the Interior to DOE.

             POWER-RELATED COSTS MUST
             BE RECOVERED THROUGH
             RATES
    ----------------------------------------------------- Appendix I:3.1.1

    The Reclamation Project Act of 1939 and the Flood Control Act of 1944
    generally require the recovery through power rates of costs of
    producing and marketing federal hydropower.  However, these acts do
    not specify which costs are to be recovered, and as demonstrated in
    our previous report,\17 the three PMAs do not recover all
    power-related costs.  The PMAs are required to recover the amount of
    their own appropriations as well as the power-related expenditures
    incurred by the operating agencies.

    The three PMAs are generally funded through the annual appropriations
    process.\18 The three PMAs receive annual appropriations to make both
    capital expenditures, such as for PMA-controlled transmission
    facilities, as well as operations and maintenance (O&M) expenditures.
    PMAs generally pay for these expenditures by requesting Treasury to
    cut checks on their respective appropriations accounts.  Unlike most
    other federal agencies, PMAs are required by law to recover through
    their rates, and repay to the Treasury, the amount appropriated for
    their power-related costs.  The payments received from PMA customers
    are deposited directly to the general fund at Treasury via a lockbox.
    Ideally, over the course of a year, collections received by Treasury
    will offset, or "repay," amounts appropriated to the PMAs for O&M
    expenses, as well as an amortized amount of capital construction
    costs.  The PMAs monitor expenses and revenues to ensure that power
    rates are sufficient to generate revenue to recover expenses.

    The PMAs are required to recover not only their own costs, but also
    the power-related expenditures incurred by the operating agencies.
    The power-related portion of the operating agencies' expenditures
    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" is allocated to the PMAs.  These joint costs
    are capital costs and O&M expenses related to both power production
    and some of the water project'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 set their rates to recover these costs from power revenues.  The
    total revenues of any project administered by a PMA are to be
    sufficient to recover O&M expenses in the year incurred and to
    recover the federal investment (appropriations) in generation and
    transmission facilities (which we refer to as appropriated debt\19 ),
    with interest, over a specified repayment period--generally 50 years
    for assets used to generate power and 35 to 45 years for assets used
    to transmit power.

    --------------------
    \17 Power Marketing Administrations:  Cost Recovery, Financing, and
    Comparison to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
    1996).

    \18 Some projects have been legislatively authorized to use revolving
    funds to finance some types of expenditures.  In addition, some
    projects use nonfederal debt as a supplemental funding source.

    \19 We call this appropriated debt because PMAs are required to repay
    appropriations used for capital investments with interest.  However,
    these reimbursable appropriations are not technically considered
    lending by Treasury.

             PMAS' DEBT
    ----------------------------------------------------- Appendix I:3.1.2

    As shown in figure I.3, the three PMAs are collectively responsible
    for repaying about $7.2 billion of debt:  $5.4 billion of
    appropriated debt,\20 $1.6 billion of irrigation debt, and about $0.2
    billion in nonfederal debt.\21 Under reclamation law, Western is
    responsible for paying the costs of certain irrigation projects that
    are judged to be beyond the ability of the irrigators to repay.\22 We
    refer to these payments as irrigation debt.  The nonfederal debt
    refers to capital provided by Western's customers (primarily through
    the issuance of bonds) to finance capital improvement projects.

       Figure I.3:  Composition of PMA
       Debt

       (See figure in printed
       edition.)

    Source:  GAO analysis of data provided by the PMAs.

    For a further discussion of the three PMAs' financing and debt, see
    our report, Power Marketing Administrations:  Cost Recovery,
    Financing, and Comparison to Nonfederal Utilities (GAO/AIMD-96-145,
    September 19, 1996), and appendix VII of this report.

    --------------------
    \20 One and one half billion dollars of the appropriated debt was
    associated with Southeastern, $3.2 billion with Western, and $686
    million with Southwestern.  Audited figures for 1996 were unavailable
    at the time of our fieldwork for Southeastern and Southwestern, so
    September 30, 1995, balances are shown.  According to the PMAs, these
    balances did not change significantly between 1995 and 1996.

    \21 All irrigation debt and nonfederal debt is attributable to
    Western.

    \22 Project authorizing legislation determines how the costs of
    constructing reclamation projects are allocated and how repayment
    responsibilities are assigned among the projects' beneficiaries.
    Collectively, the federal reclamation statutes that are generally
    applicable to all projects and the statutes authorizing individual
    projects are referred to as reclamation law.  In implementing
    reclamation law, the Bureau of Reclamation and Western are guided by
    implementing regulations, administrative decisions of the Secretary
    of the Interior and the Secretary of Energy, respectively, and
    applicable court cases.

          ROLE OF BONNEVILLE POWER
          ADMINISTRATION
    ------------------------------------------------------- Appendix I:3.2

    BPA was created in 1937 to market electric power from the Bonneville
    Dam and to construct facilities to transmit the power.  It markets
    electric power from the Federal Columbia River Power System, which
    consists of 29 federally-owned hydroelectric projects located
    primarily in the Columbia River Basin.  BPA's primary customer
    service area, as shown in figure I.2, is a 300,000 square mile area
    of the Pacific Northwest, comprised of Oregon, Washington, Idaho,
    western Montana, and small portions of California, Nevada, Utah, and
    Wyoming.  BPA sells primarily wholesale power from the dams and other
    generating plants to public and private utilities and direct service
    industries.  By law, BPA gives preference to public utilities in
    sales of power and sells only excess power outside the Pacific
    Northwest.  BPA builds, owns, and operates transmission lines that
    comprise 75 percent of the Northwest's high-voltage transmission
    capacity.  (See table I.2.)

                                        Table I.2

                                    Information on BPA

                                                                 Revenue
                           Number of                kWh sold         (in
                          hydroelect   Number of  (billions)   millions)    Miles of
                    Year  ric plants   customers      fiscal      fiscal  transmissi
                 created  Sept. 1995  Sept. 1995   year 1995   year 1995    on lines
    ----------  --------  ----------  ----------  ----------  ----------  ----------
    BPA             1937        29\a         193        80.4      $2,182      15,012
    --------------------------------------------------------------------------------
    \a BPA has entered into nonfederal debt agreements to acquire all or
    part of the generating capacity of power projects of other entities,
    including four nuclear plants and some small hydroelectric projects.

    The Federal Columbia River Power System provides roughly half the
    power used in the Pacific Northwest.  BPA, the Corps, and the Bureau
    coordinate system operation with the many public and privately owned
    utilities that own dams on the river system.  Over the years,
    Congress has expanded BPA's mission to include conservation and
    renewable resource development, rate relief for specified residential
    and small farm power users, and specific mandates for fish and
    wildlife protection and funding.

             BPA'S POWER PROGRAM IS TO
             BE SELF-SUPPORTING
    ----------------------------------------------------- Appendix I:3.2.1

    Unlike the other PMAs, BPA no longer receives an annual
    appropriation.  The Federal Columbia River Transmission System Act of
    1974 placed BPA on a self-financing basis--so that its operating
    expenses are paid for by operating revenues (power and transmission
    sales).  Funds received from customers are paid to BPA, which then
    deposits the receipts into a special BPA fund at Treasury.
    Expenditures for BPA are then paid for out of that special BPA fund
    at Treasury.  To provide for capital expenditures, BPA does have
    authority to borrow from the Treasury.  Treasury bond borrowing
    authority is capped at $3.75 billion ($2.5 billion for transmission
    and other capital investments and $1.25 billion for conservation and
    renewable energy investments).  The agency is required to set its
    rates for power and transmission sales at levels that generate
    revenues sufficient to cover annual expenses and pay back previously
    appropriated funds.  BPA is required to make an annual payment to
    Treasury that includes debt servicing costs on appropriated debt and
    Treasury bonds.  Similar to the three PMAs discussed previously, BPA
    is also required to recover and repay to the Treasury the operating
    agencies' power-related capital and operating expenses.  Unlike the
    other PMAs, BPA has a legislative mandate that requires it, within
    certain limits, to provide sufficient firm power to meet the needs of
    its primary regional customers.

             BPA'S DEBT
    ----------------------------------------------------- Appendix I:3.2.2

    As shown in figure I.4, BPA's total debt as of September 30, 1996,
    was $17.2 billion, including $6.8 billion for appropriated debt, $2.5
    billion for Treasury bonds, $7.1 billion for nonfederal debt, and
    $0.8 billion in irrigation debt.

       Figure I.4:  Composition of
       BPA's Total Debt as of
       September 30, 1996

       (See figure in printed
       edition.)

    Source:  GAO analysis of data provided by BPA.

    In the late 1960s, BPA and the region's utilities forecasted that
    electrical demand would triple between 1970 and 1990 and concluded
    that the region needed to supplement its hydroelectric capacity with
    new forms of generation.  Subsequently, BPA entered into nonfederal
    financing agreements to acquire all or part of the output of four
    nuclear power plants constructed, owned, and to be operated by other
    entities.  As part of these agreements, BPA was required to pay for
    the annual project costs, including debt service, in amounts ranging
    from 30 to 100 percent of total costs incurred.  Later, a variety of
    events, including construction cost overruns and overly optimistic
    estimates of electricity demand, made it clear that some of these
    plants would not be economical to complete or operate.  Accordingly,
    construction was halted on two of these nuclear plants and they were
    not completed.  In addition, one previously operating plant has been
    shut down permanently.  As a result, BPA is responsible for
    approximately $4.2 billion in nonfederal debt associated with three
    nonoperating nuclear plants and an additional $2.5 billion in
    nonfederal debt associated with the one operating nuclear plant.\23

    For a further discussion of BPA's financing and debt, see our report,
    Bonneville Power Administration:  Borrowing Practices and Financial
    Condition (GAO/AIMD-94-67BR, April 19, 1994), and appendix VIII of
    this report.

    --------------------
    \23 The nonfederal debt also consists of $321 million invested in
    small hydroelectric projects and conservation measures.

       THE TENNESSEE VALLEY AUTHORITY
    --------------------------------------------------------- Appendix I:4

    The Tennessee Valley Authority (TVA) is a multipurpose, independent
    federal corporation established by the Tennessee Valley Authority Act
    of 1933.\24 The act established TVA to improve the quality of life in
    the Tennessee River Valley by improving navigation, promoting
    regional agricultural and economic development, and controlling the
    flood waters of the Tennessee River.  To those ends, TVA erected dams
    and hydroelectric power facilities on the Tennessee River and its
    tributaries.  To meet the need for more electric power during World
    War II, TVA expanded beyond hydropower, building coal-fired power
    plants.  In the 1960s, TVA decided to add nuclear generating units to
    its power system to meet projected heavy growth in electricity
    demands.\25

    Today, TVA's other roles have been eclipsed by its electricity
    program.  TVA has become the nation's largest electric power
    generator, with a dependable capacity in service of over 28,000
    megawatts and 16,021 employees as of September 30, 1996.  TVA sells
    power in seven states--Alabama, Georgia, Kentucky, Mississippi, North
    Carolina, Tennessee, and Virginia--as illustrated in figure I.5.
    Additional specific information about TVA is shown in table I.3.

       Figure I.5:  TVA Service Area

       (See figure in printed
       edition.)

    Source:  Developed by GAO from data provided by TVA.

                                        Table I.3

                                    Information on TVA

                                                                 Revenue
                           Number of                kWh sold         (in
                          hydroelect   Number of  (billions)   millions)    Miles of
                    Year  ric plants   customers      fiscal      fiscal  transmissi
                 created  Sept. 1996  Sept. 1996   year 1996   year 1996    on lines
    ----------  --------  ----------  ----------  ----------  ----------  ----------
    TVA             1933        29\a      \160\b       140.6    $5,693\c      17,000
    --------------------------------------------------------------------------------
    \a These 29 plants have 109 generating units.  TVA also has 4
    additional units at a pumped storage plant, 59 units at 11 coal-fired
    plants, 48 combustion turbines at 4 sites, and 5 operating nuclear
    units at 3 plants.

    \b TVA sells primarily wholesale power.  As of September 30, 1996,
    TVA's 160 wholesale distributors--municipal and cooperatives--in turn
    sell power on a retail basis to nearly 8 million customers.  TVA also
    has about 67 directly served large industrial customers and federal
    agencies.

    \c Total operating revenues from power programs.

    --------------------
    \24 The TVA Act as amended (16 U.S.C.  831 et seq.) provides the
    basic statutory authority for TVA.

    \25 For a more detailed discussion of TVA's nuclear program, see
    Tennessee Valley Authority:  Financial Problems Raise Questions About
    Long-term Viability (GAO/AIMD/RCED-95-134, August 17, 1995).

          LEGISLATION AFFECTING TVA
    ------------------------------------------------------- Appendix I:4.1

    TVA's authorizing legislation allows it to operate with a relatively
    high degree of independence.  The TVA Act of 1933 did not subject TVA
    to the regulatory and oversight requirements that must be satisfied
    by commercial electric utilities.  As opposed to the regulatory
    environment faced by other utilities, all authority to run and
    operate TVA is vested in TVA's three-member board of directors,
    including the sole authority to set wholesale electric power rates
    and approve the retail rates charged by TVA's distributors.\26 The
    three board members are full-time employees of TVA.  They are
    appointed by the President, with the advice and consent of the
    Senate, and serve 9-year overlapping terms of office.  The President
    designates one member as the chairman.

    In 1959, the Congress amended the TVA Act in an attempt to protect
    surrounding utilities from competition with TVA because it was a
    low-cost federal utility.  By establishing what is commonly referred
    to as the TVA "fence," the 1959 amendments prohibited TVA--with some
    exceptions--from entering into contracts to sell power outside the
    service area TVA and its distributors were serving on July 1, 1957.
    TVA was allowed to continue to sell power to certain other utilities
    outside of its service area if the power is surplus to the
    requirements of TVA's own customers.  TVA can also buy power when
    needed.

    Because TVA is, for the most part, legally prohibited from making
    sales outside of its service area, the Energy Policy Act of 1992
    exempted TVA from its wheeling requirements.\27 This exemption
    prevents competitors from using TVA's transmission system to sell to
    customers inside TVA's service area.\28 TVA is therefore generally
    insulated from wholesale competition and remains in a position
    similar to a regulated utility monopoly.

    --------------------
    \26 TVA is subject to some other regulatory actions, such as the
    Nuclear Regulatory Commission's (NRC) role in licensing and
    inspecting nuclear facilities and the Environmental Protection
    Agency's environmental regulations.

    \27 Section 722 of the Energy Policy Act of 1992, 106 Stat 2919.

    \28 However, the exemption specifically did not cover the Bristol
    Virginia Utilities Board.

          TVA'S POWER PROGRAMS ARE TO
          BE SELF-SUPPORTING
    ------------------------------------------------------- Appendix I:4.2

    As mentioned, TVA's programs are divided into two types of
    activities--the nonpower programs and the power programs.  The
    nonpower programs, such as water resources, navigation, and flood
    control, are primarily funded through federal appropriations and user
    fees.  These programs received about $109 million in funding in
    fiscal year 1996 and are operated primarily within the 41,000 square
    mile Tennessee River watershed.\29 Since the 1959 amendments to the
    TVA Act, TVA's power program does not receive any federal
    appropriations and is required to be self-supporting, so that their
    operating expenses are paid for by operating revenues (power sales).
    TVA's power program generated about $5.7 billion in fiscal year 1996
    revenues, with about $5.0 billion (88 percent) of this amount coming
    from the 160 wholesale distributors.  The other 12 percent primarily
    came from sales to directly served industries and federal agencies.

    --------------------
    \29 TVA's nonpower programs were not included in the scope of this
    report.

          TVA'S DEBT
    ------------------------------------------------------- Appendix I:4.3

    Although TVA's power programs are required to be self-funded, TVA is
    authorized to use debt financing to pay for capital improvements in
    excess of internally generated funds.  In 1959, TVA was authorized to
    borrow by issuing bonds and notes with a debt limit set by the
    Congress at $750 million.  Since then, TVA's debt limit has been
    increased four times by the Congress and is currently capped at $30
    billion.  As of September 30, 1996, TVA had accumulated almost $28
    billion in debt:  $3.2 billion in direct federal borrowing from FFB
    and $24.1 billion in publicly issued TVA debt (which is not
    explicitly guaranteed by the federal government).  In addition, TVA
    is also required to repay funds appropriated to it prior to becoming
    self-funding in 1959--the outstanding balance was approximately $600
    million as of September 30, 1996.  Although we refer to this as
    appropriated debt, this amount does not count toward TVA's $30
    billion debt cap.\30

       Figure I.6:  Composition of TVA
       Debt as of September 30, 1996

       (See figure in printed
       edition.)

    Source:  GAO analysis of data provided by TVA.

    For a more detailed discussion of TVA's financing and debt, see our
    report, Tennessee Valley Authority:  Financial Problems Raise
    Questions About Long-term Viability (GAO/AIMD/RCED-95-134, August 17,
    1995), and appendix IX of this report.

    --------------------
    \30 TVA refers to this as "appropriation investment" and treats it as
    a proprietary capital account for financial statement purposes.

    OBJECTIVES, SCOPE, AND METHODOLOGY
    ========================================================== Appendix II

    The Chairman, House Committee on the Budget, and the Chairman,
    Subcommittee on Water and Power Resources, House Committee on
    Resources, asked us to review several issues relating to federal
    electricity finances.  The specific objectives of our review were to
    (1) estimate the federal government's fiscal year 1996 net recurring
    cost and, where possible, fiscal years 1992 through 1996 cumulative
    net recurring cost\1 from ongoing operations of electricity-related
    activities at the Rural Utilities Service (RUS), the Department of
    Energy's (DOE) power marketing administrations\2 (PMAs), and the
    Tennessee Valley Authority (TVA) (see appendixes IV and V) and (2)
    assess the likelihood of future losses beyond the net recurring costs
    to the federal government from the electricity-related activities of
    these entities (see appendixes VI, VII, VIII, and IX).

    As agreed with the requesters, we did not (1) estimate the forgone
    revenue for federal, state, or local governments resulting from the
    tax exempt status of the RUS borrowers, the PMAs, or TVA, (2)
    estimate the forgone revenue for federal and state governments
    resulting from tax-exempt debt instruments issued by TVA or related
    to Western or BPA nonfederal debt, (3) assess the reasonableness of
    the methodologies used by the operating agencies to allocate
    power-related costs to the PMAs for recovery, or (4) quantify the
    amount of potential future losses to the federal government.

    As also agreed with the requesters, we did not include the following
    in our review:  the Alaska Power Administration, the Federal Energy
    Regulatory Commission (FERC), the nonpower aspects of RUS and TVA,
    and the Nuclear Regulatory Commission (NRC).  As agreed, we estimated
    the net cost to the federal government on the accrual basis of
    accounting.\3

    These net costs either already have had or will have an impact on the
    federal budget.  In addition, it was beyond the scope of our review
    to evaluate the public benefits provided by the PMAs, RUS, and TVA to
    their respective regions.

    The following sections detail the methodologies used in our analyses
    and additional restrictions on the scope of our work.

    --------------------
    \1 Estimates of cumulative net costs for fiscal years 1992 through
    1996 are stated in constant 1996 dollars.

    \2 We reviewed the electricity related activities of four PMAs:
    Bonneville Power Administration (BPA), Southeastern Power
    Administration (Southeastern), Southwestern Power Administration
    (Southwestern), and Western Area Power Administration (Western).
    Because BPA faces different operating risks and its annual revenue is
    more than 2 times larger than the other three PMAs combined, we
    frequently discuss BPA separately.  Since legislation has been
    enacted to sell the Alaska Power Administration to nonfederal
    entities, it was excluded from our review.

    \3 The accrual basis of accounting recognizes the impact of revenue
    and expense transactions on the financial statements in the time
    period when they occur.

       FEDERAL GOVERNMENT'S DIRECT AND
       INDIRECT FINANCIAL INVOLVEMENT
       IN THE ELECTRICITY-RELATED
       ACTIVITIES AT RUS, THE PMAS,
       AND TVA
    -------------------------------------------------------- Appendix II:1

    Net recurring costs and exposure to additional financial losses
    result from the federal government's direct and indirect financial
    involvement in the electricity-related activities of these entities.
    For this report, we defined direct involvement in electricity
    activities as loans or loan guarantees made by the federal government
    directly to RUS borrowers and appropriated debt\4 owed by the PMAs or
    TVA.  As of September 30, 1996, the federal government had over $53
    billion of direct financial involvement.  The federal government
    would have financial losses from its direct involvement if the RUS
    borrowers or the federal entity were unable to repay debt owed to the
    federal government.

    For this report, we defined indirect involvement as nonfederal
    financing.  As of September 30, 1996, the federal government had
    indirect financial involvement of over $31 billion--primarily
    nonfederal financing of BPA\5 and bonds issued by TVA.  Although
    BPA's nonfederal financing and TVA bonds are not explicitly
    guaranteed by the federal government, the financial community
    generally views them as having an implicit federal guarantee.  The
    federal government would have losses from its indirect involvement if
    it incurred unreimbursed costs as a result of actions it took to
    prevent default on nonfederal debt service payments or breach of
    contract by the federal entity on nonfederal financing.

    --------------------
    \4 We call this appropriated debt because the PMAs are required to
    recover from ratepayers, with interest, appropriations used for
    capital investments, including funds appropriated to construct, as
    well as to operate and maintain, power-related facilities.  However,
    these amounts are not technically considered lending by Treasury.

    \5 BPA calls this "nonfederal project financing." BPA used its
    contracting authority to acquire all or part of the generating
    capability of power projects or other entities.  Under these
    agreements, BPA contracts to pay all or part of the annual project
    budgets, including debt service, whether or not the projects are
    completed.  BPA does not have the authority to borrow from nonfederal
    sources.  See appendix VIII for additional discussion.  For Western,
    nonfederal financing refers to capital provided by its customers
    (primarily through the issuance of bonds) to finance capital
    improvement projects.

       ASSESSING THE NET COST FROM
       ONGOING OPERATIONS OF
       ELECTRICITY-RELATED ACTIVITIES
       AT RUS, THE PMAS, AND TVA
    -------------------------------------------------------- Appendix II:2

    In order to assess the federal government's net recurring cost from
    ongoing operations of electricity-related activities, we defined the
    full cost of the PMAs and TVA producing and marketing federal power
    and of RUS providing loans and loan guarantees to its borrowers based
    on our review of applicable federal guidance and industry practice.
    Then, we determined whether, for each entity, (1) there is a net
    financing cost, (2) pension and postretirement health benefits were
    fully recovered, and (3) other costs were fully recovered.

    Most of the data used in our analysis was obtained from audited
    financial statements.  Independent public accounting firms or Offices
    of Inspector General audited the financial statements of RUS, the
    PMAs, and TVA in accordance with private sector and government
    auditing standards.  On the basis of their audits, the firms or
    Offices of Inspector General issued opinions on the fairness of the
    agency's financial statements and the adequacy of the agency's
    internal controls and compliance with laws and regulations.

    The 1996 financial operations of RUS were audited by the Department
    of Agriculture's (USDA) Office of Inspector General.  RUS is a
    component of USDA's rural development mission area and is included as
    part of the rural development's consolidated financial statements.
    USDA's Office of Inspector General issued a qualified opinion on the
    1996 financial statements for the rural development mission area
    because of weaknesses in the estimation and reestimation of loan
    subsidy costs related to the Federal Credit Reform Act of 1990.\6
    However, the qualification did not affect the data that we needed to
    conduct our analysis of net financing costs.  RUS' fiscal years 1992
    through 1995 financial statements were audited by Urbach Kahn &
    Werlin (UKW).  UKW issued an unqualified opinion on RUS' financial
    statements for 1992 through 1995, indicating that the financial
    statements were fairly stated in all material respects.

    BPA's financial statements are audited by Price Waterhouse.  Price
    Waterhouse issued an unqualified opinion on BPA's financial
    statements for fiscal years 1992 through 1996, indicating that the
    financial statements were fairly stated in all material respects.
    Western's fiscal years 1992 through 1996 financial statements and
    Southeastern's and Southwestern's fiscal years 1994 and 1995
    financial statements were audited by KPMG Peat Marwick (KPMG).  KPMG
    was hired by the DOE Inspector General to perform the audits of these
    PMAs.  KPMG issued an unqualified opinion on Western's fiscal years
    1992 through 1996 financial statements and on Southeastern's and
    Southwestern's fiscal years 1994 and 1995 financial statements.
    Audited financial statements for 1996 were not available for
    Southeastern and Southwestern; therefore, we used 1995 audited
    financial statements.  Southeastern's fiscal years 1992 and 1993
    financial statements were audited by Deloitte & Touche, which issued
    an unqualified opinion on them.  Southwestern's fiscal years 1992 and
    1993 financial statements were audited by RJ Miranda & Company and
    Price Waterhouse, which issued unqualified opinions on them.

    The financial statements of TVA are audited by Coopers & Lybrand,
    which issued an unqualified opinion on TVA's fiscal years 1992
    through 1996 financial statements, indicating that the financial
    statements were fairly stated in all material respects.  However, in
    1994 and 1995, the opinions also included a "matter of emphasis"
    relating to TVA's deferred nuclear assets.

    While it was not within the scope of our work to assess the overall
    quality of the auditors' work, we reviewed selected 1996 audit work
    papers (1995 audit work papers for Southeastern, Southwestern, and
    Western) and management letters to obtain background information.
    Throughout our report, where possible, we used audited numbers from
    each entity's 1996 and prior years' annual reports.  In addition,
    where possible, we used audited numbers from the 1996 and prior
    years' annual reports of IOUs and RUS generation & transmission
    cooperatives.

    We interviewed numerous officials at RUS, the PMAs, the operating
    agencies, and TVA.  We provided questions to each of the respective
    entities relating to cost recovery and other matters addressed in our
    report.  We analyzed data provided to us by the entities to determine
    which costs are and are not fully recovered from borrowers or
    ratepayers.  The net costs identified in this report focus on the
    material items we found in reviewing the data sources described in
    this appendix.  There could be additional net costs that did not come
    to our attention during this review.

    --------------------
    \6 RUS is required to budget for and report on its loans and
    guarantees in accordance with the requirements of the Federal Credit
    Reform Act of 1990 and Statement of Federal Financial Accounting
    Standards (SFFAS) No.  2, Accounting for Direct Loans and Loan
    Guarantees.  The two key principles of credit reform contained in the
    Federal Credit Reform Act center on the (1) definition of cost in
    terms of the present value of the estimated net cash flow over the
    life of a credit instrument and (2) inclusion in the budget of the
    estimated costs of credit programs before direct or guaranteed loans
    are made or modified.  The budget and accounting requirements under
    credit reform were effective for loans and guarantees made after
    October 1, 1991.  The majority of RUS electricity loans and
    guarantees were made prior to October 1, 1991 and therefore are not
    reported under credit reform requirements.  Additionally, because the
    credit reform estimates are not reliable at RUS, we chose to use
    actual costs incurred rather than any credit reform cost estimates
    for our analysis.

          DEFINING THE FULL COST OF
          PRODUCING AND MARKETING
          FEDERAL POWER AND OF
          PROVIDING LOANS AND LOAN
          GUARANTEES TO BORROWERS
    ------------------------------------------------------ Appendix II:2.1

    To define the full costs associated with producing and marketing
    federal power and of providing loans and loan guarantees to
    borrowers, we referred to Office of Management and Budget (OMB)
    Circular A-25, User Fees, which provides guidance for use in setting
    fees to recover the full costs of providing goods and services.  The
    circular defines full cost as all direct and indirect costs of
    providing goods and services and is consistent with guidance of full
    cost reporting contained in Statement of Federal Financial Accounting
    Standards (SFFAS) No.  4, Managerial Cost Accounting Concepts and
    Standards for the Federal Government and industry practice.  In
    accordance with the criteria from OMB Circular A-25,
    SFFAS No.  4, and industry practice, the full cost of producing and
    marketing power or providing loans and loan guarantees is the sum of
    all direct and indirect costs incurred by RUS, the PMAs, and TVA and
    the costs incurred by any other agencies to support the operations of
    RUS, the PMAs, and TVA.

          ASSESSING NET FINANCING
          COSTS
    ------------------------------------------------------ Appendix II:2.2

    For this report, we defined the net financing cost to the Treasury as
    the difference between Treasury's borrowing cost or interest expense
    and the interest income received from RUS borrowers, the PMAs, and
    TVA.  Our objective was to determine what the net cash flow was to
    the federal government from lending transactions with its
    electricity-related activities.\7 Treasury's borrowing cost is
    particularly relevant because the federal government has had debt
    outstanding since before 1940--before the oldest RUS borrowers and
    PMA or TVA debt still outstanding--and has had a deficit every year
    since 1969.  Thus, it is reasonable to assume that the federal
    government has had to issue debt to extend financing to RUS
    borrowers, the PMAs, and TVA.

    Our basic methodology was to determine whether the federal government
    received a return sufficient to cover its borrowing costs and, if
    not, to estimate the net financing cost.  RUS, the PMAs, and TVA had
    several forms of federal debt outstanding at September 30, 1996.
    Each of these forms of federal debt had different terms and thus
    required us to apply different variations of our basic methodology in
    assessing whether there was a net financing cost to the federal
    government and, if so, measuring the magnitude of this net cost.  The
    following are the specific methodologies used for RUS financing and
    PMA appropriated debt, TVA's appropriated debt, TVA's Federal
    Financing Bank (FFB) debt, and BPA's Treasury bonds.

    --------------------
    \7 If our objective had been to calculate an economic financing
    subsidy rather than the net cash flow to Treasury, consideration of
    other forms of subsidy would have been necessary.  For example, our
    calculation of net financing cost excludes the impact that the risk
    of federal hydropower projects might have had on the PMAs' interest
    rates if they had been financed in the private market rather than
    through Treasury.  Our methodology also does not consider the
    difference between Treasury debt being compounded semiannually versus
    PMA and RUS debt being compounded annually.

          RUS FINANCING AND PMA
          APPROPRIATED DEBT
    ------------------------------------------------------ Appendix II:2.3

    We assessed the net financing cost of the RUS loan portfolio and PMA
    appropriated debt using substantially the same methodology, which we
    refer to as the portfolio methodology.  Under this methodology, we
    obtained the amount of interest income paid to the federal government
    by RUS borrowers and the PMAs from the audited 1996 financial
    statements.\8 Since Treasury does not match its borrowing with loans
    made to RUS borrowers or the PMAs' appropriated debt financing and
    does not specifically price the debt based on its terms, the federal
    government's interest expense associated with the funds provided to
    the RUS borrowers and PMAs must be estimated.  PMA appropriated debt
    and RUS borrower loans have fixed interest rates over terms of up to
    35 years for RUS borrowers and 50 years for PMAs.  Treasury does not
    have the ability to call\9 PMA appropriated debt or RUS borrower
    loans.

    To estimate the federal government's interest expense, we used the
    weighted average interest rate on Treasury's entire outstanding bond
    portfolio because it best reflects its cost of long-term borrowing.
    The bond portfolio's average interest rate includes bonds with
    varying maturities up to 30 years.  Treasury's bond portfolio average
    interest rate of 9 percent was obtained from the Monthly Statement of
    the Public Debt of the United States as of September 30, 1996.  This
    document is published by the Bureau of Public Debt, Department of
    Treasury.  Specific calculations of interest expense using the 9
    percent Treasury cost of funds are discussed below.

    Although both PMA appropriated debt and RUS borrower loans are long
    term with fixed interest rates, application of the portfolio
    methodology varies to some extent, as described below.

    --------------------
    \8 Because audited fiscal year 1996 data were not available for
    Southeastern and Southwestern at the time of our fieldwork, we used
    fiscal year 1995 appropriated debt and weighted average interest
    rates.  According to the PMAs, these balances did not significantly
    change from 1995 to 1996.  We then estimated fiscal year 1996 net
    financing cost using the 1996 Treasury average interest rate.

    \9 Call refers to the ability of the lender to require the borrower
    to pay back the debt before its maturity date.

             RUS FINANCING
    ---------------------------------------------------- Appendix II:2.3.1

    There are four main aspects of the net financing cost to Treasury of
    the RUS debt, although not all RUS debt has each of these elements.
    The first is the difference between the RUS borrower's interest rate
    and the interest rate on the closest match of Treasury borrowing in
    terms of maturity at the time the loan was made (interest rate
    spread).  The second is that financially troubled RUS borrowers have
    missed significant scheduled loan payments (delinquent interest
    payments).  The third is that RUS borrower loans have maturities of
    up to 35 years, which is beyond the maximum maturity of Treasury
    bonds.  Thus, if RUS borrowers do not repay their loans within 30
    years, Treasury would have to refinance its corresponding debt
    (maturity differential).  The fourth is that Treasury's borrowing
    practices are inflexible in that it is generally unable to refinance
    or prepay outstanding debt in times of falling interest rates
    (Treasury borrowing practices).

    In order to calculate the net financing costs to Treasury under the
    portfolio method, we obtained the federal government's annual
    interest income from RUS borrowers from supporting financial
    statement documentation.  RUS does not recognize interest income on
    delinquent loans, which reduces its interest income.  Interest income
    on delinquent loans is recorded when it is received.

    To calculate the federal government's annual interest expense, we
    added the estimated interest expense paid by Treasury to bondholders
    to finance RUS federal debt and the interest expense paid to private
    lenders.  Interest from government borrowing was estimated by
    multiplying the amount of RUS federal government borrowing
    outstanding by the average interest rate Treasury was paying on its
    portfolio of bonds outstanding at the end of fiscal year 1996--9
    percent.  For interest expense to private lenders, we obtained the
    actual amounts paid to the lenders from supporting financial
    statement documentation and other supporting documents.  The sum of
    interest expense on federal and private debt yields an estimate of
    the amount of annual interest expense Treasury must pay on the RUS
    loan portfolio.  We obtained the total RUS debt owed to Treasury and
    FFB from the final trial ledger balance.  Finally, we subtracted the
    interest income received by Treasury from RUS borrowers from the
    estimated interest expense paid by Treasury on the RUS loan
    portfolio.  The difference between these two amounts constitutes the
    net financing costs to Treasury.  See appendix V for a detailed
    calculation of the RUS net financing cost.

             PMA APPROPRIATED DEBT
    ---------------------------------------------------- Appendix II:2.3.2

    There are four main aspects of the net financing cost to the federal
    government from the PMAs' appropriated debt, although not all PMA
    debt has each of these elements.  The first is the difference between
    the PMA borrowing rate and the interest rate on the closest match of
    Treasury borrowing in terms of maturity at the time of the
    appropriation (interest rate spread).  The second is the PMAs'
    ability to repay the highest interest-bearing appropriated debt first
    (prepayment option).  The third is that Treasury's borrowing
    practices are inflexible in that it is generally unable to refinance
    or prepay outstanding debt in times of falling interest rates
    (Treasury borrowing practices).  This inflexibility is part of the
    reason for Treasury's relatively high cost of funds--9.0 percent on
    its outstanding portfolio of bonds as of September 30, 1996.  The
    fourth is that PMA appropriated debt has maturities of up to 50
    years, which is beyond the maximum maturity of Treasury bonds.  Thus,
    if appropriated debt is not repaid within 30 years, Treasury would
    have to refinance its corresponding debt (maturity differential).

    In order to calculate the net financing costs to the Treasury under
    the portfolio method, we obtained the federal government's annual
    interest income from the PMAs by multiplying the amount of PMA
    appropriated debt outstanding at September 30, 1996, by the weighted
    average interest rate paid by the PMAs.  Appropriated debt and the
    weighted average interest rate paid by the PMAs were taken from the
    1996 audited financial statements.\10 We reconciled these figures to
    interest expense and capitalized interest reported in the PMAs'
    audited financial statements.

    To calculate interest expense for the federal government, we
    multiplied the amount of PMA appropriated debt outstanding by the
    average interest rate Treasury was paying on its portfolio of bonds
    outstanding at the end of fiscal year 1996--9 percent--which yields
    an estimate of the amount of interest expense Treasury must pay on
    the PMAs' outstanding appropriated debt.  The difference between the
    federal government's interest income and interest expense represents
    the net financing cost.  For a further discussion of PMA financing,
    see Power Marketing Administrations:  Cost Recovery, Financing, and
    Comparisons to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
    1996).

    To assess the effects of the restructuring of BPA's appropriated
    debt, we reviewed the provisions of the BPA Appropriations
    Refinancing Act and examined the mechanics of how the restructuring
    was to take place under the act.  We also discussed the restructuring
    with BPA officials and reviewed BPA documents regarding the
    implementation of the act and its effects on BPA's appropriated debt
    and interest expense.  We did not perform any calculations to
    determine the accuracy of the position taken by BPA that the present
    value of the appropriated debt after the restructuring is identical
    to the present value of this debt prior to the restructuring.  We
    also did not review the impact of the debt restructuring on the
    federal budget.

    --------------------
    \10 As previously discussed, we used 1995 data for Southeastern and
    Southwestern because their 1996 audited financial statements were not
    available.

             LOAN-BY-LOAN METHODOLOGY
    ---------------------------------------------------- Appendix II:2.3.3

    The net financing cost for RUS financing and PMA appropriated debt in
    our report is calculated using the portfolio methodology.  We also
    calculated the net financing costs to the Treasury under an
    alternative methodology we refer to as the loan-by-loan methodology.
    This methodology attempts to match the RUS federal debt and the
    appropriated debt of two of the PMAs--Southwestern and BPA--with
    Treasury borrowing.  The loan-by-loan methodology assumes that in
    order to provide up to 50-year financing for a PMA project and up to
    35-year financing for RUS debt, the Treasury must borrow an
    equivalent amount via the sale of long-term bonds.  Because Treasury
    does not borrow for more than 30-year terms, this methodology also
    assumes that when necessary, Treasury must refinance each borrowing
    to extend the financing to the PMAs or RUS borrowers for the
    remainder of the terms of the debt.

    We performed this analysis to estimate the 1996 net financing cost
    for Southwestern, BPA, and RUS.  We found that the loan-by-loan
    methodology resulted in a larger net financing cost for Southwestern
    and BPA, and the same for RUS.  Thus, the portfolio methodology is
    generally a more conservative estimate of the magnitude of the net
    financing cost for this debt.  However, the primary reason we did not
    use the loan-by-loan methodology to calculate net financing costs is
    that Treasury does not match its borrowing with RUS financing or PMA
    appropriated debt.  Thus the loan-by-loan methodology is less
    realistic than the portfolio methodology in estimating what the
    actual net cost of PMA appropriated debt and RUS financing is to the
    federal government.

          OTHER FINANCING FOR TVA AND
          BPA
    ------------------------------------------------------ Appendix II:2.4

    TVA had outstanding appropriated debt\11 and FFB debt and BPA had
    outstanding Treasury bonds at September 30, 1996.  Unlike the PMA
    appropriated debt and RUS financing, these financing arrangements
    were designed so that Treasury would recover its cost of providing
    the funds to TVA and BPA.  To determine whether TVA appropriated
    debt, TVA FFB debt, and BPA Treasury bonds resulted in a net
    financing cost to the federal government, we assessed whether the
    terms of each type of debt resulted in recovery of a reasonable
    approximation of the federal government's cost of providing the
    funds.

    --------------------
    \11 We call this appropriated debt because TVA is required to repay
    all but $258.3 million of the appropriations that were used for
    capital investments, plus interest.  However, these reimbursable
    appropriations are not technically considered lending by the
    Treasury.  In addition, TVA refers to this debt as appropriation
    investment and considers it to be equity.  Accordingly, TVA considers
    annual payments as a reduction of equity capital and the annual
    return as a dividend.  We refer to the annual payments as principal
    payments, and the annual return as interest expense.

          TVA'S APPROPRIATED DEBT
    ------------------------------------------------------ Appendix II:2.5

    As of September 30, 1996, TVA had $608 million of appropriated debt
    outstanding that represented appropriations received by TVA to
    construct its hydroelectric dams, fossil plants, transmission system,
    and other general assets of the power program.  This debt was
    incurred from the inception of TVA in 1933 through 1959.  When the
    TVA Act was amended in 1959 to give TVA the authority to
    "self-finance," TVA was required to begin making annual payments from
    net power proceeds for principal on this debt, plus a market rate of
    return (interest expense) to Treasury on the unpaid balance.  TVA's
    appropriated debt has substantially different terms than the PMAs'
    appropriated debt.  First, annual principal payments (currently $20
    million) are required for the more than 50 years from 1959 until TVA
    pays down the balance to $258.3 million.  Once the balance is $258.3
    million, TVA is required to continue to pay annual interest expense
    on this balance.  Second, the interest rate on TVA's appropriated
    debt is variable and is reset each year.  The interest rate used is
    the rate on Treasury's total marketable public obligations
    outstanding at the beginning of the year.  Thus, unlike PMA
    appropriated debt, which has a fixed interest rate for up to 50
    years, TVA's appropriated debt is similar to a variable interest rate
    loan.  As a result, TVA's interest payments to Treasury have and
    should continue to approximate Treasury's total cost of funds over
    time.

    Because the repayment terms of this debt include a 1-year variable
    interest rate, which is a short-term debt feature, and a repayment
    term of more than 50 years, which is characteristic of long-term
    debt, we concluded that use of Treasury's average interest rate for
    all marketable public obligations results in a reasonable return and
    no net cost to the federal government.

          TVA'S FEDERAL FINANCING BANK
          DEBT
    ------------------------------------------------------ Appendix II:2.6

    As of September 30, 1996, TVA had $3.2 billion of long-term debt held
    by FFB.  This debt was issued from 1985 to 1989, with maturities
    ranging from 14 to 30 years and fixed interest rates ranging from 8.5
    percent to 11.7 percent.  FFB cannot call this debt and TVA cannot
    prepay this debt unless it pays FFB the present value of the future
    cash flows using current FFB interest rates.\12 This debt matures in
    fiscal years 2003 through 2016.  For fiscal years 1992 through 1996,
    TVA had varying amounts of FFB debt outstanding.

    FFB obtains its funds by borrowing from the Department of the
    Treasury.  FFB has a stated policy to provide funds at Treasury's
    cost of money.  Each loan made by FFB matches the terms and
    conditions, except for the interest rate, of the corresponding loans
    made by Treasury to FFB.  FFB charges TVA the interest rate it incurs
    on the Treasury borrowing, plus a fee of one-eighth-of-one-percent to
    cover administrative costs.\13

    Because the interest rate on TVA's FFB debt is based on the interest
    rate paid by the Treasury on similar term debt plus a one-eighth of
    one percent administrative fee, we concluded that Treasury is
    recovering its cost of funds and that there is no net financing cost
    to the federal government.

    Recently, TVA asked FFB to allow it to repay this debt before its
    maturity dates.  However, TVA was not willing to incur the prepayment
    premiums required under the terms of the existing loan contracts with
    FFB.  In 1995, the Congressional Budget Office (CBO) was asked to
    review proposed legislation that would have authorized TVA to prepay
    $3.2 billion in loans made by FFB without paying the prepayment
    premiums.  CBO estimated that enacting such legislation in 1996 would
    have increased federal outlays by about $120 million per year through
    2002, with declining amounts thereafter until the last notes matured
    in the year 2016.  We concur with CBO's assessment.  This proposed
    legislation was never introduced.

    --------------------
    \12 FFB charges the prepayment premium to protect itself from
    incurring an economic loss on the prepayment.  This premium is
    calculated based on the difference between the book (face) value and
    the Treasury market value of the loan.  The loan's market value is
    calculated based on the net present value of the future stream of
    principal and interest payments the government gives up when FFB
    accepts prepayment of a loan.  We did not review the Congressional
    Budget Office's calculation of the increase in federal outlays that
    would result if TVA were allowed to repay its FFB debt without paying
    the prepayment premiums.

    \13 TVA also has the option of repurchasing the FFB bonds under
    standard FFB prepayment provisions.

          BPA'S TREASURY BONDS
    ------------------------------------------------------ Appendix II:2.7

    As of September 30, 1996, BPA had $2.5 billion of medium- and
    long-term debt held by Treasury in the form of BPA bonds.  Interest
    rates on this debt are fixed and are set using rates comparable to
    the debt issued by U.S.  government corporations with similar terms.
    Some of this debt is callable by BPA.  The call premium BPA paid was
    also based on premiums for similar debt.  The debt matures in fiscal
    years 1997 through 2034.  For fiscal years 1992 through 1996, BPA had
    varying amounts of FFB debt outstanding.

    We discussed the mechanics of the borrowing process with cognizant
    BPA and Treasury representatives.  In addition, we examined the
    process by which Treasury sets interest rates and call premiums.
    Because the BPA bonds result in a return to the Treasury that
    approximates its cost of funds, we believe that there is no net cost
    to the federal government.

          ASSESSING THE RECOVERY OF
          PENSION AND POSTRETIREMENT
          BENEFITS
    ------------------------------------------------------ Appendix II:2.8

    To assess whether pension and postretirement health benefits were
    fully recovered by RUS, the PMAs, and TVA, we consulted with
    representatives from the Office of Personnel Management's Office of
    Actuaries.  We determined that certain Civil Service Retirement
    System (CSRS) pension benefits were not being recovered by RUS, the
    PMAs, and TVA.  We also determined that all postretirement health
    benefits for current employees were not being recovered by RUS and
    the PMAs.  We determined that Federal Employee Retirement System
    (FERS) pension benefits are currently being fully funded by employee
    and employer contributions.

    To calculate the cost of CSRS pension benefits that were not fully
    recovered by RUS from borrowers or by the PMAs and TVA from rate
    payers, and the cost of postretirement health benefits that were not
    fully recoverd by RUS from borrowers or by the PMAs from ratepayers,
    we reviewed SFFAS No.  5, Accounting for Liabilities of the Federal
    Government, which requires all federal agencies to record the full
    cost of pension and postretirement health benefits in financial
    statements beginning in fiscal year 1997.

    SFFAS No.  5 prescribes that the aggregate entry age normal (AEAN)\14
    actuarial cost method be used to calculate pension expenses.  We
    consulted with actuaries from the Office of Personnel Management
    (OPM) to obtain an understanding of how to apply the AEAN method to
    estimate the amount by which employer and employee contributions
    toward future CSRS pension benefits fall short of the normal cost of
    those benefits.

    We determined the applicable normal cost, under the AEAN method, of
    CSRS pensions for fiscal year 1996.  For CSRS employees, OPM reported
    that in 1996, 25.14 percent of gross salaries was the full (normal)
    cost to the federal government of benefits earned that year by
    employees and that federal agencies contributed 7 percent and
    employees contributed 7 percent to OPM for CSRS, leaving a funding
    deficiency of 11.14 percent of each CSRS employee's annual salary.
    This 11.14 percent funding deficiency is applicable to federal
    agencies.  To calculate the difference between the full (normal) cost
    for CSRS pensions and the amount employees and the federal entities
    contributed, we

      -- estimated the number of full-time equivalent positions involved
         in electricity-related activities at RUS, the PMAs and TVA,
         based on information provided by each entity;

      -- estimated the number of those employees covered by the CSRS
         pension plan, based on (1) governmentwide information provided
         by OPM on the percentage of employees covered by CSRS or (2)
         information provided by the entity;

      -- multiplied that number by the average salary\15 to estimate
         total CSRS payroll expense; and

      -- multiplied the resulting number by 11.14 percent, which,
         according to OPM actuaries, represents the difference between
         the normal cost of future CSRS pensions and combined employer
         and employee contributions.

    The result is an estimate of the additional amount the entities would
    have had to contribute to fully fund CSRS pension benefits earned in
    fiscal year 1996.

    To estimate the cumulative net costs for fiscal years 1992 through
    1996 under the AEAN method for future CSRS pensions, we multiplied
    the net cost for 1996 by five.  The resulting estimate of cumulative
    net costs for CSRS pensions for the 5-year period, which we converted
    to constant 1996 dollars, is conservative because the number of CSRS
    employees has been declining.  The annual net cost, or funding
    shortfall, associated with CSRS 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.

    In addition to pensions, federal employees are eligible to receive
    postretirement health coverage, for which a portion of the premium is
    paid by the federal government.  While employed, neither federal
    employees nor their employing agencies contribute funds to pay for
    the federal government's portion of postretirement health benefits.
    For applicable employees, the PMAs do not recover this cost from
    ratepayers, and RUS does not recover this cost from borrowers.  To
    calculate the amount of the electricity-related costs for fiscal year
    1996, we again used the AEAN method, which is prescribed by SFFAS No.
    5 for estimating postretirement health benefit costs.  We estimated
    the number of relevant covered employees at each entity involved in
    electricity-related activities.  We multiplied this number for each
    employee by the 82-percent governmentwide health benefits plan
    participation rate, which we then multiplied by $2,183 (OPM's
    estimate of the annual normal cost for postretirement health benefits
    per participating employee for fiscal year 1996).  The result of this
    calculation approximates the normal cost of postretirement health
    benefits for fiscal year 1996 and the amount the entities would have
    had to contribute to fully fund postretirement health benefits earned
    that year.  As with CSRS pensions, to estimate the cumulative net
    costs for fiscal years 1992 through 1996, we multiplied the net cost
    for 1996 by five, and converted this amount to constant 1996 dollars.

    It is important to note that our calculations of annual pension and
    postretirement health benefits do not include any provision for
    retirees of each entity because the relevant actuarial information
    needed to do so was not available from OPM.

    --------------------
    \14 Under the AEAN method, which is based on dynamic economic
    assumptions, including future salary increases, the actuarial present
    value of projected benefits is allocated on a level basis over the
    earnings or the service of the group between entry age and assumed
    exit ages and should be applied to pensions on the basis of a level
    percentage of earnings.  The portion of this actuarial present value
    allocated to a valuation year is called the "normal cost."

    \15 We used governmentwide average salary information we obtained
    from OPM for CSRS employees.

          ASSESSING THE RECOVERY OF
          OTHER COSTS
    ------------------------------------------------------ Appendix II:2.9

    For this report, we defined other costs to include construction costs
    for certain projects, environmental costs legislatively precluded
    from recovery, power-related costs assigned to incomplete irrigation
    projects, deferred payments, interest expense on store supplies,
    legal costs incurred by the Department of Justice, and administrative
    appropriations not recovered.  As discussed below, to assess these
    costs we used audited financial statements, cost reports, and/or
    other provided information.  Not all of the costs were applicable to
    each agency.

    We obtained information on recovery of construction costs relating to
    the Teton Project (BPA), Russell Project (Southeastern), Truman
    Project (Southwestern), and the Washoe and Mead-Phoenix Projects
    (Western), by analyzing the PMA annual reports and other information
    provided by the PMAs and operating agencies.  For the Corps' Russell
    Project, we also reviewed records of congressional hearings on the
    project dating back to its initial approval in the 1960s.

    We used cost reports and financial statements from the PMAs and
    operating agencies to review environmental costs.  We determined that
    some environmental costs have been legislatively excluded from
    recovery in rates.  We also found some environmental costs not
    legislatively excluded that are included in rates, but we could not
    determine whether all such costs are included.  Obtaining the data
    necessary to make this determination was beyond the scope of the
    assignment.

    To identify the portion of power-related capital costs allocated to
    incomplete and unfeasible irrigation facilities at Western's
    Pick-Sloan program, we used (1) cost reports and estimates of the
    power requirements for irrigation facilities prepared by the Bureau,
    (2) cost allocation percentages prepared by the Bureau and Corps, and
    (3) reconciliations prepared by Western in their Power Repayment
    Studies and the Bureau's Statement of Project Construction Cost and
    Repayment as of September 30, 1994.  We determined that the capital
    costs allocated to incomplete or unfeasible irrigation facilities
    amounted to about $454 million as of September 30, 1994.  Based on
    our previous finding that these capital costs increased by about $5
    million annually between fiscal years 1987 and 1994,\16

    we estimated that the capital costs amounted to about $464 million as
    of September 30, 1996.  We did not verify the Bureau's cost-benefit
    calculations for determining the feasibility of its irrigation
    projects within the Pick-Sloan program.

    To identify the portion of the Corps power-related operations and
    maintenance (O&M) expenses that Western has allocated to incomplete
    irrigation facilities for financial reporting and cost recovery
    purposes, we reviewed the annual calculations made by Western to
    allocate the Corps of Engineers' annual O&M expenses based on the
    planned rather than the actual use of the irrigation facilities.

    Western has had an outstanding balance of deferred interest and O&M
    payments since at least 1988.  Within the last 5 fiscal years, the
    amount deferred ranged from a high of $250 million as of September
    30, 1994, to a low of $81 million as of September 30, 1996.  To
    assess the impact on Treasury, we analyzed the net change in the
    deferred payments amount in each of the last 5 years.  Net increases
    in the deferred amount in fiscal years 1992 through 1994 were
    reflected as net costs to the federal government.  Net decreases in
    the deferred amount in fiscal years 1995 and 1996 were reflected as
    net recoveries for the federal government.

    Western has maintained an inventory of "stores supplies" (spare parts
    used in performing maintenance, repairs, and upgrades of transmission
    facilities), averaging almost $21 million over the 5 years from 1992
    through 1996.  However, Western has not paid interest on the
    appropriated debt associated with this inventory.  We estimated the
    amount of interest that was not paid to Treasury each year by
    multiplying the stores supplies balance as of September 30 of each of
    the last 5 fiscal years by the average yield rate on 3-year
    marketable Treasury bonds issued in each of those years.  We used the
    3-year bond rate because the stores inventory turns over about once
    every 2 or 3 years.

    We assessed the recovery of legal costs the Department of Justice
    (DOJ) incurs on behalf of RUS.  We determined that DOJ's legal costs
    are not charged to RUS and are thus costs that the federal government
    incurs on RUS' behalf.  To identify DOJ's legal costs for RUS, we
    obtained information from DOJ for fiscal years 1992 through 1996.
    These costs include staff hours, salaries, benefits, travel, and
    other costs.  We also found that BPA and DOJ have an
    intergovernmental agreement in place that provides for DOJ to bill
    BPA for certain costs incurred.  The agreement specifically covers
    BPA's Washington Public Power Supply System and Tenaska litigation,
    as well as DOJ's salary, travel, and certain other costs.  We did not
    assess whether this arrangement results in the full recovery of costs
    DOJ incurs for BPA.

    We determined from discussions with USDA officials that RUS does not
    recover administrative appropriations through interest or other
    charges to borrowers.  To identify the electricity-related share of
    RUS' administrative appropriation for fiscal years 1992 through 1996,
    we obtained an estimate from USDA.  According to USDA, these
    administrative costs include funding for all direct and indirect
    costs, except the pension and postretirement health benefits
    previously discussed.

    --------------------
    \16 Federal Power:  Recovery of Federal Investment in Hydropower
    Facilities in the Pick-Sloan Program (GAO/T-RCED-96-142, May 2,
    1996).

       ASSESSING THE RISK TO THE
       FEDERAL GOVERNMENT OF FUTURE
       LOSSES FOR ELECTRICITY-RELATED
       ACTIVITIES
    -------------------------------------------------------- Appendix II:3

    In assessing the risk of future losses beyond the net recurring costs
    to the federal government from the electricity-related activities at
    the PMAs, TVA, and RUS, we used the criteria for contingencies from
    SFFAS No.  5, Accounting for Liabilities of the Federal Government.
    According to SFFAS No.  5, "A contingency is an existing condition,
    situation, or set of circumstances involving uncertainty as to
    possible gain or loss to an entity.  The uncertainty will ultimately
    be resolved when one or more future events occur or fail to occur."
    When a loss contingency exists, the likelihood that the future event
    or events will confirm the loss or the incurrence of a liability can
    range from probable to remote as follows:

      -- Probable:  The future confirming event or events are more likely
         than not to occur.

      -- Reasonably possible:  The chance of the future confirming event
         or events occurring is more than remote but less than probable.

      -- Remote:  The chance of the future event or events occurring is
         slight.

    We applied these criteria and considered different risk factors on
    the basis of discussions with agency officials and industry experts,
    analysis of financial and other data, and our professional judgment.
    It is important to note that our assessment of the likelihood of loss
    does not generally consider proceeds that the federal government
    would receive from the sale of the assets of the RUS borrowers, the
    PMAs, or TVA.

          ASSESSING RISK OF LOSS TO
          THE FEDERAL GOVERNMENT FOR
          THE RURAL UTILITIES SERVICE
          PORTFOLIO OF ELECTRIC LOANS
          AND LOAN GUARANTEES
    ------------------------------------------------------ Appendix II:3.1

    In order to assess the risk of future loss beyond the net recurring
    costs to the federal government from the electricity-related
    activities of RUS, we reviewed the $32.3 billion (as of September 30,
    1996) RUS portfolio of electric loans and loan guarantees outstanding
    to rural electric cooperatives.  The portfolio consists of loans and
    guarantees made to 782 distribution cooperatives and 55 Generation
    and Transmission (G&T) cooperatives.  We focused primarily on the
    G&Ts, since their principal outstanding is approximately $22.5
    billion, or about 70 percent of the RUS electric loan portfolio, and
    they are generally higher risk loans.  According to RUS officials,
    the G&T borrowers generally have substantial capital investment and
    debt and thus have higher-risk loans than those made to distribution
    borrowers.  The G&Ts are wholesale producers and are more vulnerable
    to current competitive pressures.  In addition, 19 of the 55 G&T
    borrowers have invested in uneconomical nuclear projects.

    We contacted Moody's Investors Service to obtain their views on the
    risk of loss from the RUS portfolio and to gain an understanding of
    issues facing the cooperatives.  We reviewed the list of 13 G&T
    borrowers that RUS has identified as financially stressed.  According
    to RUS reports, about $10.5 billion of the $22.5 billion in G&T debt
    is owed by the 13 financially stressed borrowers.  We ascertained
    from RUS why each of the 13 was placed on the list.  Of these, four
    G&T borrowers are in bankruptcy with about $7 billion in outstanding
    debt.  The remaining 9 borrowers have investments in uneconomical
    nuclear generating plants and/or have requested or plan to request
    financial assistance from RUS.  We obtained and reviewed agency
    documents with write-off information for fiscal years 1992 through
    1996.  We also discussed with RUS and DOJ officials the loan
    write-offs to date, the 13 financially stressed borrowers, and the
    potential for future write-offs.

    To assess the ability of RUS G&T cooperatives to withstand
    competitive pressures, we analyzed the average revenue per
    kilowatthour (kWh) of 33 G&T borrowers that are not currently
    considered financially stressed by RUS.  We excluded the 9 G&Ts that
    only transmit electricity and the 13 financially stressed borrowers.
    As of September 30, 1996, the loans outstanding for these 33 G&Ts
    were about $11.7 billion of the $22.5 billion in G&T loans
    outstanding.  We compared the average revenue per kWh for these
    borrowers with North American Electric Reliability Council (NERC)
    regional averages for investor-owned utilities (IOUs) and
    publicly-owned generating utilities (POGs).  We obtained the average
    revenue per kWh for the 33 borrowers from RUS statistical reports and
    verified the numbers to the borrowers' annual reports and the
    borrowers' audited financial statements, when available.  In
    addition, RUS staff verified the numbers.  We obtained a report on
    electric cooperatives from Moody's Investors Service, which
    corroborated our data.  (See appendix III for a further discussion of
    average revenue per kWh.)

          ASSESSING RISK OF FUTURE
          LOSS TO THE FEDERAL
          GOVERNMENT FOR THE PMAS AND
          TVA
    ------------------------------------------------------ Appendix II:3.2

    To assess the risk of future loss beyond the net recurring costs to
    the federal government from the electricity-related activities of the
    PMAs and TVA, we analyzed each agency based on several key factors.
    We interviewed government bond analysts at Fitch Investors Service
    and at Moody's to determine the factors they use to analyze the
    financial condition of electric utilities and provide bond ratings.
    The specific factors that we used to analyze each agency included
    cost of electricity production and rates, key financial ratios,
    generating mix, competitive environment, management actions, and
    legislative and other factors.  Because of the unique characteristics
    of each PMA and TVA, not all factors were applicable to each agency.
    We also identified mitigating factors that reduce the probability of
    loss for each agency.  Based on our assessment of the risks and
    mitigating factors, we determined whether the risk of future loss
    beyond the net recurring costs to the federal government was
    probable, reasonably possible, or remote.  For BPA, we assessed the
    risk of loss (1) through the year 2001 and (2) after the year 2001.
    For TVA, we assessed the risk of loss (1) with protections from
    competition and (2) without barriers to competition.

    To assess the competitiveness of the PMAs and TVA, we compared the
    average revenue per kWh for wholesale sales of each entity to the
    average revenue per kWh for wholesale sales of IOUs and POGs in the
    primary NERC region that each entity operates.  We also compared the
    average revenue per kWh of each of the three PMAs' rate-setting
    systems to IOUs and POGs in each system's NERC region.\17 We
    determined that IOUs and POGs were the appropriate "industry group"
    to compare to the PMAs and TVA because they generate and transmit
    electricity and sell some power at wholesale.  Our comparisons are
    particularly relevant because many power customers are primarily
    concerned with cost of production and resultant electricity rates
    when choosing their electricity suppliers.  We did not include
    nongenerating publicly owned utilities.  These utilities ordinarily
    have no generating assets and thus are not comparable from an
    operating or financial perspective.

    To assess the flexibility of BPA and TVA to respond to competitive
    pressures, we computed the ratio of financing costs to revenue for
    each entity and nonfederal utilities by dividing financing costs by
    operating revenue.  The financing costs include interest expense on
    short-term and long-term debt, appropriated debt for BPA and TVA, and
    preferred and common stock dividends for the IOUs.  Preferred and
    common stock dividends were included in the IOUs' financing costs to
    reflect the difference in the capital structure of these entities
    from BPA and TVA.  We also computed the ratio of fixed financing
    costs to revenue for TVA and neighboring IOUs.  For TVA, we limited
    our comparison group to 11 IOUs\18 that border on TVA's service area
    because industry experts told us that due to the cost of transmitting
    electricity, TVA's competition would most likely come from IOUs
    located close to its service area.  For example, the Bristol Virginia
    Utilities Board has terminated its power contract with TVA and agreed
    to purchase its electric power from Cinergy, one of the IOUs in our
    comparison group.  We calculated this ratio by dividing financing
    costs less common stock dividends by operating revenue for the fiscal
    year.  We excluded common stock dividends from the IOUs' financing
    costs because they are not contractual obligations that have to be
    paid.

    To assess changes in the environment in which BPA operates and
    potential measures that may be taken in response to these changes, we
    reviewed the final report from the Comprehensive Review of the
    Northwest Energy System that was initiated by the governors of the
    states that BPA serves.  Since the review's recommendations have not
    been implemented, we did not assess the effect they would have on the
    federal government's financial risk.  In addition, we examined the
    extent to which BPA's financial reserves provide additional
    flexibility in BPA's attempts to respond to competitive pressures.
    We did not, however, perform an independent evaluation of BPA's $325
    million fish contingency reserve or the credits BPA takes annually
    for fish migration costs.

    To compare the amount of deferred assets and capital costs that TVA
    has compared to neighboring IOUs, we computed the following two
    ratios for 1996.

      -- The ratio of accumulated depreciation and amortization to gross
         property, plant and equipment (PP&E) was calculated by dividing
         accumulated depreciation and amortization by gross PP&E at
         fiscal year-end.

      -- The ratio of deferred assets to gross PP&E was calculated by
         dividing deferred assets by gross PP&E at fiscal year-end.
         Deferred assets include construction work-in-progress and
         deferred nuclear units (for TVA only).  Deferred nuclear units
         are included for TVA because they are treated by TVA as
         construction work-in-progress (that is, not depreciated).

    To compute the investment in utility plant per megawatt of generating
    capacity for the PMAs, TVA, and nonfederal utilities, we divided
    gross PP&E by the utilities' generating capacity at fiscal year-end.
    For the IOUs, we used the nameplate generating capacity at fiscal
    year-end 1995.  For TVA, we used the winter net dependable generating
    capacity as of September 30, 1996.  We used TVA's capacity figure as
    of September 30, 1996, to reflect the two nuclear units that TVA
    brought on line during fiscal year 1996.  For the IOUs, we computed
    average system retail rates by dividing total retail electricity
    revenues by total kilowatt hours sold.  To calculate the average
    system retail rates\19 for TVA, we multiplied the percentage of
    retail sales by TVA's residential, commercial, and industrial sales
    by the retail sales for each category.  Then, we totaled these
    amounts to compute the weighted average system retail rate for TVA.

    To assess the status of TVA's power program, we examined the history
    and current operation of TVA's nuclear power program and TVA's
    prospects for converting the partially completed Bellefonte Nuclear
    Plant to a fossil plant.  We focused on TVA's nuclear power program
    because it is associated with a substantial portion of TVA's $27.9
    billion of debt, and because it has experienced problems over the
    past 20 years.  We reviewed previous GAO, TVA, and Nuclear Regulatory
    Commission reports on TVA's nuclear power program.  We examined TVA's
    program for operating, maintaining, and upgrading its nonnuclear
    power assets, primarily its coal-fired and hydroelectric units.  The
    coal-fired and hydroelectric units are important because in fiscal
    year 1996, approximately 65 percent of TVA's generation was from
    coal-fired units and 11 percent was from hydroelectric units.  For
    the coal-fired and hydroelectric units, we reviewed TVA's projected
    capital expenditures through the year 2001.  We obtained data on
    TVA's plans to upgrade or retire these units and its assessments of
    the costs of complying with environmental requirements, including the
    Clean Air Act requirements.

    To gain an understanding of the concerns of the PMAs' customers, we
    contacted organizations representing major PMA customers.  These
    groups were formed to facilitate communication between the PMAs and
    their customers and to raise concerns where appropriate.  For all
    four PMAs, we obtained the groups' perspectives on the impact of
    deregulation on the electricity industry.  For BPA, we also obtained
    the groups' viewpoints on the reasonableness of BPA's attempts to
    renew contracts with existing customers before they expire in 2001.
    Because most of our concerns with Southeastern, Southwestern, and
    Western relate to individual rate-setting systems, we specifically
    addressed issues related to these systems' competitiveness with the
    appropriate customer group.  Where the customer group corroborated
    information from the three PMAs on the competitiveness of an
    individual rate-setting system, we did not independently verify it,
    and we attributed any views reported.

    To gain an understanding of the concerns of TVA's customers, we
    contacted regional associations that represent TVA's distributors and
    large industrial customers.  We also interviewed officials from some
    of TVA's largest distributors (which represent over 30 percent of
    TVA's energy sales), including the municipal utilities of
    Chattanooga, Knoxville, Memphis, and Nashville, Tennessee.  We
    interviewed officials from the Bristol, Tennessee, and Fort Payne,
    Alabama, utilities in order to gain the perspectives of TVA's smaller
    municipal distributors.  We also interviewed officials from the
    Bristol Virginia Utilities Board because the utility has terminated
    its power contract with TVA and agreed to purchase its electric power
    from another utility beginning January 1, 1998.  We interviewed
    officials from the Four County Electric Power Association in
    Columbus, Mississippi, because the utility had terminated its power
    contract with TVA, but the utility subsequently withdrew its
    termination notice and decided to remain in the TVA system.  We
    analyzed the provisions of TVA's power contracts to determine how
    difficult it would be for a distributor to cancel its contract.  We
    examined recent modifications that some distributors have made to the
    cancellation notice requirements in their contracts.  We also
    examined recent agreements not to exercise termination rights that
    some distributors have signed.

    A list of the organizations that we contacted during the course of
    our work follows.  We conducted our review between January 1997 and
    July 1997 in accordance with generally accepted government auditing
    standards.  We obtained written comments on a draft of our report,
    which are contained in appendixes X through XIII.

    --------------------
    \17 Unlike the three PMAs, BPA is comprised of a single rate-setting
    system.

    \18 The 11 IOUs and their subsidiary utilities used in our comparison
    included (1) American Electric Power Company (including Appalachian
    Power, Columbus Southern Power, Indiana Michigan Power, Kentucky
    Power, Kingsport Power, Ohio Power, and Wheeling Power), (2) Carolina
    Power & Light Company, (3) Cinergy Corp.  (including Cincinnati Gas &
    Electric and PSI Energy), (4) Dominion Resources, Inc.  (including
    Virginia Electric Power), (5) Duke Power Company, (6) Entergy
    Corporation (including Arkansas Power & Light, Gulf States Utilities,
    and Mississippi Power & Light), (7) Illinova Corporation (including
    Illinois Power), (8) KU Energy Corp.  (including Kentucky Utilities
    Co.), (9) LG&E Energy Systems (including Louisville Gas and
    Electric), (10) SCANA Corporation (including South Carolina Electric
    & Gas), and (11) The Southern Company (including Alabama Power,
    Georgia Power, Gulf Power, and Mississippi Power).

    \19 TVA sells wholesale power to its distributors who then sell it at
    retail rates.  In performing this calculation, we used TVA's
    distributors' retail rates.

       ORGANIZATIONS THAT GAO
       CONTACTED
    -------------------------------------------------------- Appendix II:4

    The following are the organizations that GAO contacted during the
    course of its work.

          FEDERAL AGENCIES
    ------------------------------------------------------ Appendix II:4.1

    Congressional Budget Office
    Department of Agriculture, Office of the Inspector General and Rural
     Utilities Service
    Department of Defense, U.S.  Army Corps of Engineers
    Department of Energy, including the Energy Information Administration
     and Office of the Inspector General
    Department of the Interior, Bureau of Reclamation
    Department of Justice
    Department of Treasury, including the Federal Financing Bank
    Nuclear Regulatory Commission, Atlanta Region
    Office of Management and Budget
    Office of Personnel Management, Office of Actuaries

          BOND RATING AGENCIES
    ------------------------------------------------------ Appendix II:4.2

    Fitch Investors Service, Inc., New York, New York
    Moody's Investors Service, New York, New York

          INDEPENDENT PUBLIC
          ACCOUNTING FIRMS
    ------------------------------------------------------ Appendix II:4.3

    Coopers & Lybrand L.L.P.
    KPMG Peat Marwick LLP
    Price Waterhouse LLP
    Urbach Kahn and Werlin P.C.

          ELECTRIC UTILITIES OR
          HOLDING COMPANIES
    ------------------------------------------------------ Appendix II:4.4

    Entergy, New Orleans, Louisiana
    Southern Company, Atlanta, Georgia

          CUSTOMER REPRESENTATIVE OR
          TRADE GROUPS
    ------------------------------------------------------ Appendix II:4.5

    Direct Service Industries, Inc., Portland, Oregon
    Electric Power Supply Association, Washington, D.C.
    Northern California Power Agency, Palo Alto, California
    Northwest Irrigation Utilities, Portland, Oregon
    Northwest Requirements Utilities, Portland, Oregon
    Pacific Northwest Utilities Conference Committee, Portland, Oregon
    Public Power Council, Portland, Oregon
    Southeastern Federal Power Customers, Alabama
    Southwestern Power Resources Association, Tulsa, Oklahoma
    Tennessee Valley Energy Reform Coalition, Knoxville, Tennessee
    Tennessee Valley Industrial Committee/Associated Valley Industries,
     Columbia, Tennessee
    Tennessee Valley Public Power Association, Chattanooga, Tennessee

          TVA DISTRIBUTORS
    ------------------------------------------------------ Appendix II:4.6

    Bristol, Virginia
    Bristol, Tennessee
    Chattanooga, Tennessee
    Four County Electric Power Association, Columbus, Mississippi
    Fort Payne, Alabama
    Knoxville, Tennessee
    Memphis, Tennessee
    Nashville, Tennessee
    Paducah, Kentucky

    AVERAGE REVENUE PER KILOWATTHOUR
    FOR WHOLESALE SALES
    ========================================================= Appendix III

       AVERAGE REVENUE PER
       KILOWATTHOUR IS AN INDICATOR OF
       POWER PRODUCTION COSTS
    ------------------------------------------------------- Appendix III:1

    In a competitive market for a relatively homogeneous product like
    electricity, being among the lowest cost producers is generally the
    most important factor in determining competitive position.  As the
    electricity industry responds to deregulation, the ability to keep
    power production costs low will enhance an entity's competitive
    position.  To assess power production costs, we examined the average
    revenue per kilowatthour (kWh) for each entity in our report.

    The average revenue per kWh for wholesale sales (sales for resale) is
    referred to as average revenue per kWh.  The average is calculated by
    dividing total revenue from the sale of wholesale electricity by the
    total number of wholesale kilowatthours sold.  Because the power
    marketing administrations (PMAs), publicly-owned generating utilities
    (POGs), and rural electric cooperatives generally recover costs
    through rates with no profit, average revenue per kWh should reflect
    the power production costs of the PMAs, POGs, and rural electric
    cooperatives.  This assumes that the entity's competitive position is
    such that it can charge sufficiently high rates to recover all costs
    from customers.  For investor-owned utilities (IOUs), average revenue
    per kWh should reflect cost plus the regulated rate of return.  Given
    that a large portion--an average of 79 percent over the last 5
    years--of IOU rate of return (net income) is paid out in common stock
    dividends, which is a financing cost, average revenue per kWh also
    approximates power production costs for IOUs.

    The Energy Information Administration (EIA) cautions that average
    revenue per unit of energy sold should not be used as a substitute
    for the price of power.  The price that any one utility charges for
    wholesale energy comprises numerous transaction-specific factors,
    including the fees charged for reserving a portion of capacity,
    consumption during peak and off-peak periods, and the use of the
    facilities.  These fees are influenced by factors such as time of
    delivery, quantity of energy, surcharges, and reliability of supply.
    For example, some Western project revenues include a legislatively
    mandated surcharge that is not related to production costs.

    In the current electricity market, utilities generally are able to
    recover their fixed costs from captive retail customers.  When
    competing for new wholesale customers, utilities with excess capacity
    that are able to recover their fixed costs from retail customers are
    able to sell excess output at a price that does not reflect the full
    cost of producing that electricity (i.e., they can sell that power at
    marginal cost).  Consequently, in some cases average revenue per kWh
    may not reflect full power production costs.  However, despite these
    limitations, average revenue per kWh is a good indicator of
    production costs since over time utilities must recover all costs to
    remain in business.  We therefore believe that average revenue per
    kWh reflects today's competitive environment.  In addition, bond
    rating services such as Moody's Investors Service use average revenue
    per kWh as one factor to assess competitive position.

    In volume 1 and appendixes VI, VII, and VIII, we compare the average
    revenue per kWh for RUS Generation and Transmission Cooperatives
    (G&T) borrowers, the three PMAs, and BPA to the North American
    Electric Reliability Council (NERC)\1 regions in which they operate
    because the factors related to individual entities' regional markets
    are still the key determinant of the competitive position of each
    entity.  NERC consists of 10 regional reliability councils\2 and
    encompasses essentially all the power systems of the contiguous
    United States, as well as parts of Canada and Mexico.  Because the
    latest available data on average revenue per kWh by NERC region are
    for 1995, we used the 1995 NERC configuration, which shows only nine
    councils.  A new regional council that encompasses much of Florida
    was added in 1996.  Figure III.1 illustrates the location of the NERC
    regions of the contiguous United States as of 1995.

       Figure III.1:  NERC Regions of
       the Contiguous United States,
       as of 1995

       (See figure in printed
       edition.)

    Source:  North American Electric Reliability Council.

    --------------------
    \1 NERC was formed by the electric utility industry to promote the
    reliability and adequacy of the bulk power supply in the electric
    utility systems of North America.

    \2 In addition to its 10 regional councils, NERC has 1 affiliate
    council member, the Alaska Systems Coordinating Council (ASCC).

    SUMMARY OF NET COSTS
    ========================================================== Appendix IV

    The net costs to the federal government resulting from its
    involvement in the electricity-related activities of four of the
    Department of Energy's power marketing administrations (PMAs),\1
    Tennessee Valley Authority (TVA), and the Department of Agriculture's
    Rural Utilities Service (RUS) are summarized in table IV.1.  The
    first four categories of net costs (net financing, loan write-offs,
    pensions and postretirement health benefits, and construction) are
    discussed in volume 1 of this report.  The remaining categories are
    referred to as "Other" net costs in volume 1 and are briefly
    explained below.  See appendix II for a discussion of our methodology
    for estimating the net costs.  Also see our September 19, 1996,
    report for additional information regarding some of these costs.\2

                                        Table IV.1

                            Net Costs for Fiscal Year 1996 and
                            Fiscal Years 1992 Through 1996 in
                         Constant 1996 Dollars for RUS, TVA, and
                                         the PMAs

                                  (Dollars in millions)

                                                                   Total Costs
                                                              ----------------------
                                                                           1992-1996
                                                                           (Constant
                                                                                1996
                 RUS     TVA     BPA    SEPA    SWPA    WAPA      1996      dollars)
    --------  ------  ------  ------  ------  ------  ------  --------  ------------
    Net         $874            $377     $68     $42     $98    $1,459        $6,941
     financi
     ng\
    Loan         982                                               982         1,049
     write-
     offs
    Benefits       1      $1      21       3       2      11        39           199
    Construc                             30\                        30          139\
     tion
    Environm                                              28        28           144
     ental
    Deferred                                           (114)     (114)          (74)
     payments
    Administ      21                                                21           110
     rative
     appropr
     iations
    DOJ                                                                            1
     costs
    Irrigati                                              16        16            80
     on
    Stores                                                 1         1             6
     invento
     ry
    ================================================================================
    Total     $1,878      $1    $398    $101     $44     $40    $2,462        $8,597
    --------------------------------------------------------------------------------
    Note:  Totals may not add due to rounding.

    --------------------
    \1 The PMAs are Bonneville, Southeastern, Southwestern, and Western
    Area Power Administrations, which are referred to as BPA, SEPA, SWPA,
    and WAPA, respectively.

    \2 Power Marketing Administrations:  Cost Recovery, Financing, and
    Comparison to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
    1996).

       NET FINANCING COSTS
    -------------------------------------------------------- Appendix IV:1

    For RUS, the net financing cost represents the difference between the
    annual interest income received by the federal government from RUS
    borrowers and the federal government's annual interest expense to
    provide the funds.  For the PMAs, the net financing cost represents
    the difference between interest income received by the federal
    government on appropriated debt and the federal government's related
    interest expense.  See appendix II for a further description of the
    methodologies used in estimating net financing costs and appendix V
    for more information about RUS' net financing costs.

       LOAN WRITE-OFFS
    -------------------------------------------------------- Appendix IV:2

    RUS has recently written off a substantial dollar amount of loans to
    rural electric cooperatives under Department of Justice (DOJ)
    authority.  RUS wrote off about $982 million of debt in fiscal year
    1996 and a total of about $1.05 billion (in constant 1996 dollars)
    over the 5-year period 1992-1996.  In addition, at the time of our
    review, RUS had written off $502 million in fiscal year 1997.  The
    most significant write-offs are related to Generation and
    Transmission Cooperatives (G&T) borrowers.  See volume 1 of this
    report for more information.

       PENSION AND POSTRETIREMENT
       HEALTH BENEFITS
    -------------------------------------------------------- Appendix IV:3

    RUS, the PMAs, and TVA\3 do not recover the full costs to the federal
    government of providing Civil Service Retirement System (CSRS)
    pension benefits to current federal employees.  Nor do RUS and the
    PMAs recover the full costs to the federal government of providing
    postretirement health benefits to current federal employees.  We
    estimate that the net CSRS pension and postretirement health benefit
    cost totaled about $39 million in fiscal year 1996 and about $199
    million in constant 1996 dollars over the 5-year period 1992-1996.\4

    --------------------
    \3 TVA has a small number of employees who transferred to TVA from
    federal agencies and continued to be covered by federal pension
    programs--CSRS or the Federal Employees Retirement System (FERS).
    TVA has its own pension system, which is fully funded.  TVA employees
    are not covered by the Federal Employees Health Benefits Program
    (FEHBP).

    \4 Our analysis covered pension and postretirement health benefit
    costs for current employees only.  The costs associated with retired
    employees were not considered because the data necessary to do so was
    not available from the Office of Personnel Management (OPM).

       CONSTRUCTION COSTS
    -------------------------------------------------------- Appendix IV:4

    Construction costs are comprised of interest that is not paid to
    Treasury each year for two construction projects.  As discussed in
    appendix VII, interest is capitalized each year on the nonoperational
    portion of the Russell Project, marketed by Southeastern.  The
    unrecovered interest totaled about $30 million in fiscal year 1996
    and about $138 million (in constant 1996 dollars) over the 5-year
    period 1992-1996.  In addition, interest was not paid to Treasury on
    the money spent to construct the Teton Dam, which would have been
    marketed by BPA.  The Teton Dam failed in 1976 when construction was
    nearly complete.  The Teton costs have been carried on the Bureau of
    Reclamation's books as construction work-in-progress even though
    construction was halted 20 years ago, and no interest has accrued
    since 1976.  The unrecovered interest related to the Teton Dam
    totaled about $236,000 in fiscal year 1996 and about $1.2 million (in
    constant 1996 dollars) over the 5-year period 1992-1996.

       ENVIRONMENTAL MITIGATION COSTS
    -------------------------------------------------------- Appendix IV:5

    Two projects, 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 have been
    legislatively excluded from Western's power rates.  The 1991 Energy
    and Water Development Appropriations Act specified that any increases
    in purchased power at the Shasta Dam caused by bypass releases
    related to fisheries preservation in the Sacramento River not be
    allocated to power.  Western officials believe that the bypass
    releases will be eliminated or minimized by the construction of a
    temperature control device at the Shasta Dam, which was recently
    completed.  These net costs totaled about $15.3 million in fiscal
    year 1996 and about $53.8 million (in constant 1996 dollars) over the
    5-year period 1992-1996.

    The Grand Canyon Protection Act of 1992 exempted from recovery
    certain costs of mitigating the environmental impact of river flow
    fluctuations at the Glen Canyon Dam.  The act states that certain
    costs of environmental impact studies related to the Glen Canyon Dam
    are not to be repaid by power customers, but it includes a provision
    that these costs could become the responsibility of the power
    customers under certain circumstances.  The power-related costs for
    environmental mitigation at the Glen Canyon Dam totaled about $12.8
    million in fiscal year 1996 and about $90.3 million (in constant 1996
    dollars) over the 3-year period since the legislative exemption,
    1994-1996.

       DEFERRED PAYMENTS
    -------------------------------------------------------- Appendix IV:6

    As of September 30, 1996, Western had deferred operations and
    maintenance (O&M) and interest expense payments totalling about $81
    million.  This balance was $114 million less than the $195 million
    outstanding as of September 30, 1995.  Because of the net repayments
    in fiscal years 1995 ($56.2 million in constant 1996 dollars) and
    1996 ($114 million) of interest and O&M expenses deferred in prior
    years, the deferred payment figures in table IV.1 are negative.

    Deferred payments are to be repaid to Treasury, with interest.
    Western officials expect to recover the majority of the deferred
    payments outstanding as of September 30, 1996, over time.

       ADMINISTRATIVE APPROPRIATIONS
    -------------------------------------------------------- Appendix IV:7

    The annual administrative appropriation to RUS includes salary
    expenses for RUS employees as well as travel, data processing, and
    other administrative support expenses.  These costs are not passed on
    to RUS borrowers.  The estimated electricity-related share of the RUS
    administrative appropriation was about $21 million in fiscal year
    1996 and about $110 million (in constant 1996 dollars) over the
    5-year period 1992-1996.

       DEPARTMENT OF JUSTICE COSTS
    -------------------------------------------------------- Appendix IV:8

    The DOJ costs primarily represent hours worked by DOJ attorneys on
    litigation related to RUS' electricity-related activities.  In 1996,
    DOJ attorneys spent about 5,700 hours working on RUS cases.  These
    costs are not charged to RUS and therefore are not passed on to RUS
    borrowers.  Judiciary costs related to RUS include salaries and
    benefits received by DOJ attorneys and expenses for travel, printing,
    and expert witnesses.  We estimate that DOJ's total judiciary costs
    on behalf of RUS were about $453,000 in fiscal year 1996 and about
    $1.4 million (in constant 1996 dollars) over the 5-year period
    1992-1996.

       IRRIGATION
    -------------------------------------------------------- Appendix IV:9

    Substantial capital costs for hydropower facilities and water storage
    reservoirs of the Pick-Sloan Missouri Basin Program have been
    allocated to authorized irrigation facilities that are incomplete and
    infeasible.  Western is currently selling electricity to power
    customers that irrigators would have used if the irrigation projects
    had been completed.  If the costs had been allocated based on actual
    use, they would have been allocated primarily to power and recovered
    through power rates within 50 years, with interest.  We estimate that
    these capital costs--which we previously reported increased by an
    average of nearly $5 million annually between fiscal years 1987 and
    1994,\5 --totaled about $464 million as of September 30, 1996.

    Interest on the $464 million in capital expenditures is not being
    paid.  Using the 3 percent interest rate that was in effect for power
    projects when construction began, we estimate that the net interest
    cost was about $13.8 million in fiscal year 1996 and about $70.6
    million (in constant 1996 dollars) over the 5-year period 1992-1996.
    In addition, annual O&M expenses that otherwise would have been
    allocated primarily to power and repaid from electricity rates have
    also been allocated to the incomplete irrigation facilities.  If
    these expenses had been allocated to power, they would have been
    included in Western's annual O&M expenses and recovered from power
    customers.  We estimate that the net irrigation O&M expense was about
    $2.1 million in fiscal year 1996 and about $9.8 million (in constant
    1996 dollars) over the 5-year period 1992-1996.

    --------------------
    \5 Federal Power:  Recovery of Federal Investment in Hydropower
    Facilities in the Pick-Sloan Program (GAO/T-RCED-96-142, May 2,
    1996).

       STORES INVENTORY
    ------------------------------------------------------- Appendix IV:10

    Western has maintained an inventory of "stores supplies," which are
    spare parts used in performing maintenance, repairs, and upgrades of
    transmission facilities, averaging almost $21 million over the 5-year
    period 1992-1996.  As noted by Western's external financial auditor,
    Western has not paid interest to Treasury on the amount of money
    spent to purchase this inventory.  However, in response to our
    questions, Western officials stated that they will begin recovering
    interest on the stores supplies in fiscal year 1997.  We estimate
    that the net interest expense associated with the stores supplies was
    about $1.2 million in fiscal year 1996 and about $6.1 million (in
    constant 1996 dollars) over the 5-year period 1992-1996.

    RURAL UTILITIES SERVICE'S NET
    FINANCING COST
    =========================================================== Appendix V

    A net financing cost exists in the Rural Utilities Service (RUS)
    electric program because the annual interest income received from RUS
    borrowers is substantially less than the federal government's annual
    interest expense to provide the funds to the electric borrowers.
    Interest income is affected by favorable rates and terms given to
    some borrowers and also by financially troubled RUS borrowers who
    have missed scheduled loan payments.  According to RUS reports, about
    $10.5 billion is owed by 13 financially stressed wholesale producers
    that we refer to as Generation and Transmission Cooperatives (G&T)
    borrowers.  See appendix VI for a risk assessment of the RUS loan
    portfolio.

    As shown in table V.1, using the portfolio methodology discussed in
    appendix II, we estimate that net financing costs (interest expense
    minus interest income) to the federal government for the RUS electric
    program for fiscal year 1996 were about $874 million; cumulatively,
    over the last 5 years, we estimate that the net financing costs
    totaled about $3.8 billion (in constant 1996 dollars).  These net
    financing costs reflect net interest expense incurred by Treasury in
    providing the funding for RUS electric loans; therefore, they do not
    correspond to RUS appropriations for these years.

                                   Table V.1

                       Financing Costs to the Government

                             (Dollars in millions)

                                                                 1992-1996
                                                                 (Constant
                                                                      1996
                                                        1996      dollars)
    ------------------------------------------------  ------  ------------
    Interest income
    Electric loans                                    $1,853       $10,813
    Interest expense
    Debt to U.S. government                            2,477        13,396
     (FFB/Treasury)
    Debt to private lenders                              250         1,229
    ======================================================================
    Net financing costs                               $(874)      $(3,812)
    ----------------------------------------------------------------------

       INTEREST INCOME
    --------------------------------------------------------- Appendix V:1

    RUS interest income is initially affected by favorable loan rates
    given to some borrowers compared to the government's cost of
    borrowing.  Until the Rural Electrification Act was amended in 1973,
    almost all financing was through direct loans from the Rural
    Electrification Administration (REA) to electric borrowers at a fixed
    rate of 2 percent with maturities up to 35 years.  However, the 1973
    amendment to the act increased the interest rate on the direct loans
    from 2 percent to 5 percent.  At the same time, loans were also made
    available (through REA) to borrowers from the newly created Federal
    Financing Bank (FFB) at the cost of money to the government.  In
    1993, the act was amended again, and the direct loan standard rate of
    5 percent was changed to provide direct loans with an interest rate
    that is (1) tied to an index of municipal borrowing rates or (2)
    fixed at 5 percent.  Most loans are now made at the municipal rate
    with or without a 7-percent cap.  Certain borrowers with customers
    that have low consumer and household incomes and high residential
    retail rates qualify for a loan at the 5-percent hardship interest
    rate.  See appendix I for a description of RUS' electric loans.

    In addition to the favorable interest rates received by some
    borrowers, RUS interest income is also affected by financially
    stressed borrowers' failure to make scheduled loan payments.
    According to RUS reports, about $10.5 billion of the $22.5 billion in
    G&T debt is owed by 13 financially stressed G&T borrowers.  RUS
    defines financially stressed borrowers as those borrowers that have
    defaulted on their loans, had their loans restructured but continue
    to experience financial difficulties, declared bankruptcy, or
    formally requested financial assistance from RUS.  Interest income is
    not recorded on delinquent debt until it is received.

    Financially stressed borrowers' failure to make scheduled payments
    can have a significant impact on interest income.  For example, one
    G&T borrower, Cajun Electric, has not been required to make interest
    payments on its $4.2 billion debt since filing for bankruptcy in
    December 1994.  In addition, Cajun made total principal payments of
    only about $19 million from December 1994 through the end of fiscal
    year 1996.  Based on Cajun's contractual interest rate of about 8.6
    percent, RUS has forgone interest income of about $30 million per
    month, or about $1 million per day, since December 1994.  In the
    meantime, the government continues to incur interest expense on
    financing related to this loan.

       INTEREST EXPENSE
    --------------------------------------------------------- Appendix V:2

    The federal government's annual interest expense on funds provided
    for the RUS electric program is determined based on outstanding RUS
    borrowing from FFB, Treasury, and private lenders.  Debt to FFB and
    Treasury totaled $27.5 billion (see table V.2) while debt to private
    lenders totaled about $2.7 billion for the fiscal year ending
    September 30, 1996.

                                        Table V.2

                          Weighted Average Interest Expense for
                              Fiscal Years 1992 Through 1996

                                  (Dollars in millions)

                                1992        1993        1994        1995        1996
    --------------------  ----------  ----------  ----------  ----------  ----------
    Debt to FFB/           $27,881.9   $27,567.8   $27,387.0   $27,855.3   $27,484.6
     Treasury
    Weighted average          .09505      .09323      .09229      .09134      .09012
     Treasury rate
    ================================================================================
    Weighted average        $2,650.2    $2,570.1    $2,527.5    $2,544.3    $2,476.9
     interest expense
    --------------------------------------------------------------------------------
    FFB debt on the electric program totaled $20.5 billion as of
    September 30, 1996.  FFB obtains funds to make loans from Treasury.
    The RUS electric program also had a total of $7 billion in direct
    borrowing from Treasury at the end of fiscal year 1996.  As shown in
    table V.2, to calculate the federal government's interest expense for
    RUS lending activities, we multiplied the total RUS debt owed to
    Treasury and FFB by the annual weighted average Treasury rate for
    each fiscal year.

    To calculate interest expense for RUS debt with private lenders, we
    totaled the actual amounts paid to the lenders based on RUS audited
    financial statements and supporting documents.  In conjunction with
    certain troubled debt restructuring, RUS assumed notes payable to
    private lenders for debt it previously guaranteed.  A substantial
    portion of these balances is owed to the National Rural Utilities
    Cooperative Finance Corporation, a private lender to rural electric
    borrowers.  The notes bear interest at rates ranging from 7.13 to
    10.70 percent and mature through the year 2020.

    RISK ASSESSMENT FOR THE RURAL
    UTILITIES SERVICE ELECTRIC
    PORTFOLIO
    ========================================================== Appendix VI

    From fiscal year 1996 through July 31, 1997, the Rural Utilities
    Service (RUS) wrote off $1.5 billion in electric loans.\1 As of
    September 30, 1996, $10.5 billion of the $32.3 billion total electric
    portfolio represented loans to borrowers that are in bankruptcy or
    otherwise financially stressed.  It is probable that the federal
    government will continue to incur substantial losses from loan
    write-offs relating to RUS borrowers that are currently bankrupt or
    financially stressed.  It is also probable that future losses will
    arise from other RUS borrowers with high production costs and the
    inability to raise rates because of regulatory and/or market
    pressures.

    --------------------
    \1 These write-offs were included in our analysis of net costs to the
    federal government in volume I.

       THE FEDERAL GOVERNMENT'S
       FINANCIAL INVOLVEMENT
    -------------------------------------------------------- Appendix VI:1

    As of September 30, 1996, the RUS electric loan and loan guarantee
    portfolio totaled $32.3 billion.  The bulk of the portfolio is made
    up of loans to the Generation and Transmission Cooperatives (G&Ts).
    The principal outstanding on these G&T loans is approximately $22.5
    billion, about 70 percent of the RUS electric loan portfolio.
    Distribution borrowers make up the remaining 30 percent of the
    electric portfolio.  Most of the RUS electric loans and loan
    guarantees were made during the late 1970s and early 1980s.  For
    example, from fiscal years 1979 through 1983, RUS approved loans and
    loan guarantees of about $29 billion, whereas during fiscal years
    1992 through 1996, it approved a total of about $4 billion in
    electric loans and loan guarantees.  There are currently 55 G&T
    borrowers and 782 distribution borrowers.  Our review focused on the
    G&T loans since they make up the majority, in terms of dollars, of
    the portfolio and generally pose the greatest risk of loss to the
    federal government.  The federal government incurs financial losses
    when borrowers are unable to repay the balance owed on their loans
    and the government does not have sufficient legal recourse against
    the borrower to recover the full loan amount.  In all instances, G&T
    loans are collateralized; however, RUS has never foreclosed on a
    loan.  RUS generally has been unable to successfully pursue
    foreclosure once the borrower files for bankruptcy because the
    borrower's assets are protected until the proceedings are settled.
    In addition, in recent cases where debt was written off, the
    government forgave the debt and therefore will not attempt to pursue
    further collection.

       SUBSTANTIAL LOAN WRITE-OFFS
       OCCURRED IN RECENT YEARS
    -------------------------------------------------------- Appendix VI:2

    Under Department of Justice (DOJ) authority, RUS has recently written
    off a substantial dollar amount of loans to rural electric
    cooperatives.  The total amount of debt written off between fiscal
    year 1992 and July 31, 1997, is about $1.5 billion.  The most
    significant write-offs relate to two G&T loans.  In fiscal year 1996,
    one G&T made a lump sum payment of $237 million to RUS in exchange
    for RUS writing off and forgiving the remaining $982 million of its
    RUS loan balance.  The G&T's financial problems began with its
    involvement as a minority-share owner in a nuclear project that
    experienced lengthy delays in construction as well as severe cost
    escalation.  When construction of the plant began in 1976, its total
    cost was projected to be $430 million.  However, according to the
    Congressional Research Service, the actual cost at completion in 1987
    was $3.9 billion as measured in nominal terms (1987 dollars).  These
    cost increases are due in part to changes in Nuclear Regulatory
    Commission (NRC) health and safety regulations after the Three Mile
    Island accident.  The remaining portion is generally due to inflation
    over time and capitalization of interest during the delays.  The
    borrower defaulted in 1986, had its debt restructured in 1993, and
    finally had its debt partially forgiven in September 1996.  This
    borrower is no longer in the RUS program.

    In the early part of fiscal year 1997, another G&T borrower made a
    lump sum payment of approximately $238.5 million in exchange for
    forgiveness of its remaining $502 million loan balance.  The G&T and
    its six distribution cooperatives borrowed the $238.5 million from a
    private lender, the National Rural Utilities Cooperative Finance
    Corporation.  The G&T had originally borrowed from RUS to build a
    two-unit coal-fired generating plant and to finance a coal mine that
    would supply fuel for the generating plant.  The plant was built in
    anticipation of industrial development from the emerging shale oil
    industry.  However, the growth in demand did not materialize, and
    there was no market for the power.  Although the borrower had its
    debt restructured in 1989, it still experienced financial
    difficulties due to a depressed power market.  RUS and DOJ decided
    that the best way to resolve the matter was to accept a partial lump
    sum payment on the debt rather than force the borrower into
    bankruptcy.  The borrower and its member distribution cooperatives
    are no longer in the RUS program.

       ADDITIONAL LOSSES FROM
       FINANCIALLY STRESSED G&T LOANS
       ARE PROBABLE IN THE SHORT TERM
    -------------------------------------------------------- Appendix VI:3

    It is probable that RUS and DOJ will have additional loan write-offs
    and therefore that the federal government will incur further losses
    in the short term from loans to borrowers that have been identified
    as financially stressed by RUS management.  Borrowers considered
    financially stressed have either defaulted on their loans, had their
    loans restructured but are still experiencing financial difficulty,
    declared bankruptcy, or have formally requested financial assistance
    from RUS.  According to RUS reports, about $10.5 billion of the $22.5
    billion in G&T debt is owed by 13 financially stressed G&T borrowers,
    as shown in table VI.1.\2 These borrowers are designated as A through
    M in table VI.1.  At RUS' request, we only identified, by name,
    distressed borrowers that were in bankruptcy.  Of these, four G&T
    borrowers are in bankruptcy with about $7 billion in outstanding
    debt.  The remaining nine borrowers have investments in uneconomical
    generating plants and/or have formally requested financial assistance
    in the form of debt forgiveness from RUS.

                                   Table VI.1

                          RUS Financially Stressed G&T
                     Cooperatives, as of September 30, 1996

                             (Dollars in millions)

                                                                Total debt
    Borrower                                                   outstanding
    --------------------------------------------------  ------------------
    Borrower A\a,b                                                $1,619.6
    Borrower B                                                       167.9
    Borrower C                                                       103.2
    Borrower D\b                                                     562.3
    Borrower E\b                                                     183.3
    Borrower F\a,b                                                 1,101.2
    Borrower G\a,b                                                 4,154.8
    Borrower H\b                                                     313.4
    Borrower I\b                                                     354.8
    Borrower J                                                     1,070.7
    Borrower K                                                       445.1
    Borrower L                                                       351.7
    Borrower M\a                                                      92.8
    ======================================================================
    Total debt                                                   $10,520.8
    ----------------------------------------------------------------------
    \a Cooperative in bankruptcy.

    \b State regulated cooperative.

    As indicated above, much of the financially troubled borrowers'
    problems stem from their investments in nuclear-generating plants
    that were completed late and over budget or in coal-fired generating
    plants that were built to satisfy anticipated industrial growth that
    did not materialize.  The investments in nuclear plants by RUS
    borrowers are for the most part minority interests in plants
    constructed by one or more investor-owned utilities (IOUs).
    According to RUS officials, among the reasons the plant investments
    became uneconomical included rapidly increasing construction and
    material costs, changing NRC regulations, and soaring interest rates.
    Concurrent with these higher costs, projected demand for energy, in
    many cases, did not materialize.  These investments resulted in high
    levels of debt and debt-servicing requirements, making power produced
    from these plants expensive.  Since cooperatives are nonprofit
    organizations, there is little or no profit built into their rate
    structure, which helps keep electric rates as low as possible.
    However, the lack of retained profit generally means the cooperatives
    have little or no cash reserves to draw upon.  Thus, when cash flow
    is insufficient to service debt, cooperatives must raise electricity
    rates and/or cut other costs enough to service debt obligations.  If
    they are unable to do so, they may default on their government loans.

    The following is a brief discussion of each of the 13 financially
    stressed G&T borrowers:

    Borrower A:  Invested in construction of a nuclear plant that
    experienced cost overruns and was never completed.  The state
    commission denied rate increases to cover the cost of the
    cooperative's investment in the plant.  The borrower defaulted on its
    loan in 1984 and declared bankruptcy in 1985.  The bankruptcy
    proceedings have been in court for 12 years and are still not
    completely resolved.

    Borrower B:  Made an investment in a nuclear plant that proved to be
    uneconomical.  While this borrower does not appear to be currently
    experiencing financial difficulties, RUS considers them financially
    stressed because they have formally requested financial assistance
    due to impending competitive pressures.

    Borrower C:  Made an investment in a nuclear plant that proved to be
    uneconomical.  While this borrower does not appear to be currently
    experiencing financial difficulties, RUS considers them financially
    stressed because they have formally requested financial assistance
    due to impending competitive pressures.

    Borrower D:  Uses primarily coal-fired generation.  The borrower
    overbuilt due to anticipated growth in electricity demand that did
    not occur.  During construction of a new plant, economic conditions
    in the area changed and demand for electricity dropped, which
    resulted in less revenue than predicted from the plant.  The
    cooperative was repeatedly denied rate increases to cover the cost of
    its plants by the state commission.

    Borrower E:  Has a small percentage share in a nuclear plant that
    proved to be uneconomical.  The borrower has substantially higher
    electricity rates than the IOUs in its region.  The cooperative has
    been denied rate increases to cover its losses by the state
    commission.  Although the borrower has had some of its debt
    refinanced, it is still experiencing financial difficulties.

    Borrower F:  A G&T with primarily coal-fired generating plants that
    overbuilt due to anticipated industrial growth related to two large
    aluminum smelting companies.  When aluminum prices dropped in the
    early 1980s, the companies threatened to move their operations if the
    cooperative did not lower electricity rates.  The state commission
    denied rate increases over the fear of losing these industries.  RUS
    restructured the borrower's debt in 1987 and 1990.  The cooperative
    filed for bankruptcy in September 1996 because its other creditors
    were unwilling to negotiate.

    Borrower G:  Built a coal-fired plant and invested in a nuclear plant
    in the mid-1970s which was completed late and experienced
    construction cost overruns.  Several factors contributed to the
    cooperative's heavy debt, including excess electricity generation
    construction resulting from overestimation of the demand for
    electricity during the 1980s.  The new capacity was intended to serve
    a growth in demand that did not materialize.  The state commission
    disapproved a rate increase and instead lowered rates to a level
    which precluded full debt service coverage.  The commission also
    refused to support a restructuring agreement that included a
    significant RUS loan write-off.\3 The rate increase was requested by
    the cooperative because of its high costs.  The borrower filed for
    bankruptcy in December 1994.

    Borrower H:  Invested in construction of a nuclear plant that proved
    to be uneconomical.  The project was completed 10 years late and over
    budget.  In addition, there was a dramatic drop in the demand for
    electricity in the cooperative's service area and the state
    commission would not allow rate increases to recover capital
    investment.  The borrower had its debt restructured in 1987; however,
    it is requesting additional financial assistance due to anticipated
    competitive pressure.  A final settlement between RUS and the
    borrower was reached in June 1997.  The borrower will receive a
    write-off of $165 million.  The final payment and related debt
    write-off will not occur until December 30, 1997.

    Borrower I:  Invested in a clean-burning coal plant that experienced
    severe cost overruns.  The borrower has substantially higher
    electricity rates than the IOUs in its region.  The state commission
    has denied the cooperative's request for rate increases.  The
    borrower had some of its debt refinanced, but it is still
    experiencing financial difficulty.

    Borrower J:  Invested in a nuclear plant that proved to be
    uneconomical.  The plant was completed late, which resulted in cost
    overruns.  As a result, the cooperative's wholesale power rates are
    very high.  The borrower has requested debt restructuring due to its
    high cost of production and anticipated competitive pressure.

    Borrower K:  Invested in a nuclear plant that proved to be
    uneconomical.  The plant was completed late which resulted in severe
    cost overruns.  The cooperative's wholesale power rates are very
    high, which has resulted in extreme unrest in the member distribution
    cooperatives.  The borrower is surrounded by IOUs with lower
    wholesale rates.  In addition, the borrower's system is very
    difficult and expensive to maintain and experiences frequent power
    outages.  The borrower has requested financial assistance because of
    anticipated competitive pressure.

    Borrower L:  Invested in a nuclear plant that proved to be
    uneconomical.  The plant was completed late, which resulted in severe
    cost overruns.  The cooperative has only five member distribution
    cooperatives, which makes it difficult to cover its high production
    costs.  This borrower chose not to declare bankruptcy and is seeking
    financial assistance.  This borrower has refinanced its debt to lower
    its interest rate, but is still experiencing financial difficulty and
    has requested additional financial assistance.

    Borrower M:  Invested in a nuclear plant that proved to be
    uneconomical.  In addition, the cooperative had a stagnant customer
    base in the 1980s.  RUS tried to negotiate a restructuring agreement,
    but the state commission denied two separate plans.  In April 1996,
    the borrower filed for bankruptcy.

    In several instances noted above, state regulatory commissions denied
    the rate increases necessary for the G&Ts to cover their costs and
    service their RUS loans although several commissions had approved the
    projects prior to construction.  Seven of the 13 financially stressed
    borrowers operate in states where regulatory commissions must approve
    rate increases.  These commissions may deny a request for a rate
    increase if they believe such an increase will have a negative impact
    on the region.

    According to RUS and DOJ officials, in the Wabash Valley bankruptcy
    case (borrower A), RUS recently received a legal decision which was
    unfavorable to its interests and may encourage additional requests
    for debt forgiveness from other RUS borrowers.  In this case, the
    effect of the court's decision was to allow the borrower to repay
    only a portion of its RUS debt, even though RUS argued that such a
    ruling sets a precedent that may allow other cooperatives to avoid
    repaying their debts.  RUS officials indicated that numerous
    borrowers, including all of the financially stressed borrowers, have
    already inquired about obtaining debt relief as a result of, among
    other things, the unfavorable legal decision.  Although several of
    the financially stressed borrowers previously had their debts
    restructured, some are again in severe financial trouble.

    --------------------
    \2 In our previous report, Rural Development:  Financial Condition of
    the Rural Utilities Service's Loan Portfolio (GAO/RCED-97-82, April
    11, 1997), we noted 12 G&T and distribution borrowers that were
    delinquent or in financial distress.  However, in this report, we
    discuss 13 financially stressed G&T borrowers identified by RUS
    management.  The primary difference is that this report does not
    include one financially stressed distribution borrower, but did
    include two borrowers that have officially requested financial
    assistance as discussed following table VI.1.

    \3 In states that regulate cooperatives, the state commission must
    approve restructuring agreements between the cooperative and its
    creditors.

       SOME LOSSES FROM LOANS
       CURRENTLY CONSIDERED VIABLE ARE
       PROBABLE IN THE FUTURE
    -------------------------------------------------------- Appendix VI:4

    In addition to the financially stressed loans, RUS has loans
    outstanding to G&T borrowers that are currently considered viable by
    RUS but may become stressed in the future due to high costs and
    competitive or regulatory pressures.  We believe it is probable that
    the federal government will eventually incur losses on some of these
    G&T loans.

    We believe the future viability of these G&T loans will be determined
    based on their ability to be competitive in a deregulated market.  In
    order to assess the ability of RUS cooperatives to withstand
    competitive pressures, we focused on the average revenue per
    kilowatthour (kWh) of 33 of the 55 G&T borrowers with loans
    outstanding of about $11.7 billion as of September 30, 1996.  We
    excluded 9 G&Ts that only transmit electricity and the 13 financially
    stressed borrowers discussed above.  Our analysis shows that for 27
    of the 33 G&T borrowers, average revenue per kWh was higher in their
    respective North American Electric Reliability Council (NERC)
    regions\4 than IOUs and 17 of the 33 were higher than publicly-owned
    generating utilities (POGs), as shown in figures VI.1 to VI.8.  These
    borrowers are designated as Borrowers 1 through 33 in figures VI.1 to
    VI.8.  The number of borrowers adds to more than 33 because some
    overlap NERC regions and thus are shown more than once.  The
    relatively high average production costs indicate that the majority
    of G&Ts may have difficulty competing in a deregulated market.  RUS
    officials told us that several borrowers have already asked RUS to
    renegotiate or write off their debt because they do not expect to be
    competitive due to high costs.  RUS officials stated that they will
    not write off debt solely to make borrowers more competitive.

    As with the financially stressed borrowers, some of the G&T borrowers
    currently considered viable have high debt costs because of
    investments in uneconomical plants.  In addition, according to RUS
    officials, there are two unique factors that cause cost disparity
    between the G&Ts and IOUs.  One factor is the sparser customer
    density per mile for cooperatives and the corresponding high cost of
    providing service to the rural areas.  A second factor has been the
    inability to refinance higher cost Federal Financing Bank (FFB) debt
    when lower interest rates have prevailed.  However, RUS officials
    said that recent legislative changes which enable cooperatives to
    refinance FFB debt with a penalty may help align G&T interest rates
    with those of the IOUs.

       Figure VI.1:  Average Revenue
       per kWh for G&Ts in the
       Southeastern Electric
       Reliability Council (SERC)
       Region

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from RUS, preliminary
    (unaudited) 1995 IOU data from the Energy Information Administration
    (EIA), and POG data from the American Public Power Association
    (APPA).

       Figure VI.2:  Average Revenue
       per kWh for G&Ts in the
       Southwest Power Pool (SPP)
       Region

       (See figure in printed
       edition.)

    Note:  Borrower 31 serves both the Electric Reliability Council of
    Texas (ERCOT) and SPP regions.

    Source:  Developed by GAO based on data from RUS, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

       Figure VI.3:  Average Revenue
       per kWh for G&Ts in the
       Electric Reliability Council of
       Texas (ERCOT) Region

       (See figure in printed
       edition.)

    Note:  Borrower 31 serves both the ERCOT and SPP regions.

    Source:  Developed by GAO based on data from RUS, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

       Figure VI.4:  Average Revenue
       per kWh for G&Ts in the
       Mid-America Interconnected
       Network (MAIN) Region

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from RUS, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

       Figure VI.5:  Average Revenue
       per kWh for G&Ts in the
       Mid-Continent Area Power Pool
       (MAPP) Region

       (See figure in printed
       edition.)

    Note:  Borrower 26 serves both the WSCC and MAPP regions.

    Source:  Developed by GAO based on data from RUS, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

       Figure VI.6:  Average Revenue
       per kWh for G&Ts in the East
       Central Area Reliability
       Coordination Agreement (ECAR)
       Region

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from RUS, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

       Figure VI.7:  Average Revenue
       per kWh for G&Ts in the Western
       Systems Coordinating Council
       (WSCC) Region

       (See figure in printed
       edition.)

    Note:  Borrower 26 serves both the WSCC and MAPP regions.

    Source:  Developed by GAO based on data from RUS, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

       Figure VI.8:  Average Revenue
       per kWh for G&Ts in the Alaska
       Systems Coordinating Council
       (ASCC) Region

       (See figure in printed
       edition.)

    Note:  Comparison includes POGs only; data for IOUs unavailable for
    ASCC.

    Source:  Developed by GAO based on data from RUS, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

    In the short-term, G&Ts will likely be shielded from competition in
    the wholesale market because of the all-requirements wholesale power
    contracts between the G&Ts and their member distribution
    cooperatives.  With rare exceptions, these long-term contracts
    obligate the distribution cooperatives to purchase all of their
    respective power needs from the G&T.  In fact, RUS requires the terms
    of the contracts to be at least as long as the G&T loan repayment
    period.  However, wholesale power contracts have been challenged
    recently in the courts by several distribution cooperatives because
    of the obligation to purchase expensive G&T power.  According to RUS
    officials, one bankrupt G&T's member cooperatives are currently
    challenging their wholesale power contracts in court in order to
    obtain less expensive power.  RUS officials believe that the
    long-term contracts will come under increased scrutiny and potential
    renegotiation or court challenges as other sources of less expensive
    power become available.

    Wholesale rates under these contracts are currently set by a G&T's
    board of directors with approval from RUS.  In states in which the
    public utility commissions regulate cooperatives, the borrower must
    file a request with the commission for a rate increase or decrease.
    Several of the currently bankrupt borrowers were denied requests for
    rate increases from state commissions.  However, RUS officials
    indicated they do not expect G&Ts to pursue rate increases as a means
    to recover their costs because of the recognition of declining rates
    in a competitive environment.  RUS officials also acknowledge that
    borrowers with high costs are likely to request debt forgiveness as a
    means to reduce costs in order to be competitive in the future.

    --------------------
    \4 We used the 1995 NERC configuration because the latest available
    data on average revenue per kWh by NERC region were for 1995; NERC's
    configuration changed in 1996.  See appendix III for a further
    discussion.

    RISK ASSESSMENT FOR SOUTHEASTERN,
    SOUTHWESTERN, AND WESTERN
    ========================================================= Appendix VII

    The three power marketing administrations (PMAs)\1 have about $5.4
    billion of appropriated debt, and Western has an additional $1.6
    billion of irrigation debt and $165 million of nonfederal debt.  The
    three PMAs market power that is substantially lower in cost than
    nonfederal utilities, which indicates that, in the current operating
    environment, they are competitively sound overall.  However, all
    three PMAs have one or a few projects or rate-setting systems with
    problems that make risk of some loss to the federal government
    probable.  The federal government, to varying degrees, is at risk of
    losing at least some of its investment in six projects/rate-setting
    systems:  the Russell Project (Southeastern), Truman Project
    (Southwestern), Central Valley Project (Western), Pick-Sloan Program
    (Western), Mead-Phoenix Transmission Line (Western), and Washoe
    Project (Western).

    --------------------
    \1 The three PMAs are Southeastern Power Administration, Southwestern
    Power Administration, and Western Area Power Administration.

       THE FEDERAL GOVERNMENT'S
       FINANCIAL INVOLVEMENT
    ------------------------------------------------------- Appendix VII:1

    The federal government has substantial financial involvement in the
    activities of the three PMAs.  As shown in table VII.1, the federal
    government's direct financial involvement, which consists of
    appropriated debt and irrigation debt, is more than $7 billion, and
    its indirect financial involvement, consisting of nonfederal debt at
    Western, is about $165 million.

                                  Table VII.1

                         Federal Government's Financial
                      Involvement in the Three PMAs as of
                    September 30, 1996 or September 30, 1995

                             (Dollars in millions)

                                        Direct           Indirect
                                ----------------------  ----------
                                Appropriat  Irrigation  Nonfederal
    PMA                            ed debt        debt        debt   Total
    --------------------------  ----------  ----------  ----------  ------
    Southeastern                  $1,491\a                          $1,491
    Southwestern                     686\a                             686
    Western                          3,217      $1,635        $165   5,017
    ======================================================================
    Total                           $5,394      $1,635        $165  $7,194
    ----------------------------------------------------------------------
    \a Because audited September 30, 1996, data were not available for
    Southeastern and Southwestern at the time of our fieldwork, we used
    September 30, 1995, appropriated debt balances for these two
    entities.  According to the PMAs, these balances did not
    significantly change from 1995 to 1996.

          DIRECT FINANCIAL INVOLVEMENT
    ----------------------------------------------------- Appendix VII:1.1

    Appropriated debt consists of appropriations, which must be repaid
    with interest, primarily used to construct the generating and
    transmission facilities\2 related to the projects for which the three
    PMAs market power.

    Western also is responsible for repaying irrigation-related
    construction costs on certain irrigation facilities, which we refer
    to as irrigation debt.  Some project-specific authorizing
    legislation\3 provides for irrigation debt to be recovered primarily
    by power revenues.  This irrigation debt is to be repaid without
    interest.  Although irrigation debt is scheduled to be recovered with
    power revenues, Western does not view irrigation debt as a power
    cost.  Therefore, when Western repays these amounts, neither the
    costs nor the related revenues will be in its financial statements.
    To the extent irrigation debt is repaid through electricity rates,
    Western's power customers are subsidizing irrigators.

    For direct involvement, the federal government would have a financial
    loss if the PMAs were unable to repay principal or interest on debt
    owed to the federal government.

    --------------------
    \2 Southeastern has no transmission facilities.

    \3 Project-specific authorizing legislation determines how the costs
    of constructing reclamation projects are allocated and how repayment
    responsibilities are assigned among the projects' beneficiaries.
    Collectively, the federal reclamation statutes that are generally
    applicable to all projects and the statutes authorizing individual
    projects are referred to as reclamation law.  In implementing
    reclamation law, the Bureau of Reclamation and Western are guided by
    implementing regulations, administrative decisions of the Secretary
    of the Interior and the Secretary of Energy, respectively, and
    applicable court cases.  Reclamation law provides for Western to use
    its power revenues to repay Treasury a certain portion of the capital
    costs allocated to completed irrigation facilities that are
    determined by the Secretary of the Interior to be beyond the ability
    of the irrigators to repay (irrigation assistance).

          INDIRECT FINANCIAL
          INVOLVEMENT
    ----------------------------------------------------- Appendix VII:1.2

    The federal government's indirect financial involvement, which
    consists of nonfederal debt related to certain projects marketed by
    Western, is about $165 million.  The nonfederal debt is capital
    provided by Western's customers (primarily through the issuance of
    bonds) to finance capital improvement projects.  The customers pay
    the debt service cost, and Western records the bond proceeds as a
    liability and records interest expense.  Western then bills the
    customers for the production costs of electricity, including the debt
    service, and credits the customers for the debt service costs.
    Essentially, this arrangement results in customers directly paying
    for capital projects rather than paying for them indirectly through
    rates.

    For indirect involvement, the federal government would have a
    financial loss if it incurred unreimbursed costs in an effort to
    prevent Western from breaching agreements to service its nonfederal
    debt.

       THE THREE PMAS ARE
       COMPETITIVELY SOUND OVERALL
    ------------------------------------------------------- Appendix VII:2

    The three PMAs market power that is substantially lower in cost than
    power sold by nonfederal utilities, which indicates that they are
    currently competitively sound overall.  The PMAs' low average revenue
    per kilowatthour (kWh)\4 are the result of their cost recovery
    structure,\5 other inherent cost advantages, and management actions
    to control costs.  We also noted some disadvantages that the three
    PMAs experience because they are federal entities.

    --------------------
    \4 See appendix III for a discussion of average revenue per kWh as an
    indicator of power production costs.

    \5 Cost recovery structure refers to the three PMAs' ability to
    exclude certain costs from rates, called "unrecovered costs." Certain
    unrecovered costs may be recoverable in the future.

          AVERAGE REVENUE PER KWH HAS
          BEEN SUBSTANTIALLY LOWER
          THAN NONFEDERAL UTILITIES
    ----------------------------------------------------- Appendix VII:2.1

    Overall, the three PMAs' average revenue per kWh were more than 40
    percent below those of other nonfederal utilities for 1995.
    Moreover, GAO previously found\6 that the three PMAs' average revenue
    per kWh were consistently 40 percent or more below nonfederal
    utilities for the years 1990 through 1994.  This indicates that the
    three PMAs, overall, are fairly well-positioned for an increased
    competitive environment resulting from deregulation.  However, the
    three PMAs' competitive position could be eroded if they are required
    to recover additional power-related costs and/or if increased
    competition in the electric utility industry causes wholesale and
    retail electricity rates to significantly drop.  Figure VII.1
    illustrates the difference between the average revenue per kWh for
    these PMAs compared to investor-owned utilities (IOUs) and
    publicly-owned generating utilities (POGs) for 1995 in the primary
    North American Electric Reliability Council (NERC) regions in which
    the PMAs operate.\7 See appendix III for a map of the NERC regions of
    the contiguous United States.

       Figure VII.1:  Average Revenue
       per kWh of Wholesale Power
       Sold, 1995

       (See figure in printed
       edition.)

    Legend

    SEPA/SERC = Southeastern/Southeastern Electric Reliability Council
    SWPA/SPP = Southwestern/Southwest Power Pool
    WAPA/WSCC = Western/Western Systems Coordinating Council

    Source:  Developed by GAO based on data from the PMAs' 1995 annual
    reports, preliminary (unaudited) 1995 IOU data from the Energy
    Information Administration (EIA), and POG data from the American
    Public Power Association (APPA).

    In addition to an overall assessment of the PMAs' costs, we compared
    the average revenue per kWh of each of the three PMAs' rate-setting
    systems\8 to IOUs and POGs in each system's geographic area.  Except
    for a few rate-setting systems at Western and Southeastern, the three
    PMAs' average revenue per kWh by rate-setting system are about 40 to
    50 percent below those of other nonfederal utilities for 1995.
    Figures VII.2 through VII.9 show a comparison of average revenue per
    kWh for each of the PMAs' 17 rate-setting systems to the relevant
    NERC region.\9 This detailed comparison is particularly relevant
    because PMA rates are set at a rate-setting system level.  Some
    rate-setting systems market power in more than one NERC region and
    thus are shown in more than one figure.

       Figure VII.2:  Comparison of
       Average Revenue per kWh by
       Southeastern Rate-setting
       System for the SERC Region,
       1995

       (See figure in printed
       edition.)

    Legend

    GA/AL/SC = Georgia/Alabama/South Carolina system.

    Source:  Developed by GAO based on data from Southeastern's 1995
    annual report, preliminary (unaudited) 1995 IOU data from EIA, and
    POG data from APPA.

       Figure VII.3:  Comparison of
       Average Revenue per kWh by
       Southwestern Rate-setting
       System for the Southwest Power
       Pool (SPP) Region, 1995

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from Southwestern's 1995
    annual report, preliminary (unaudited) 1995 IOU data from EIA, and
    POG data from APPA.

       Figure VII.4:  Comparison of
       Average Revenue per kWh by
       Southwestern Rate-setting
       System for the Electric
       Reliability Council of Texas
       (ERCOT) Region, 1995

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from Southwestern's 1995
    annual report, preliminary (unaudited) 1995 IOU data from EIA, and
    POG data from APPA.

       Figure VII.5:  Comparison of
       Average Revenue per kWh by
       Southwestern Rate-setting
       System for the Mid-Atlantic
       Interconnected Network (MAIN)
       Region, 1995

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from Southwestern's 1995
    annual report, preliminary (unaudited) 1995 IOU data from EIA, and
    POG data from APPA.

       Figure VII.6:  Comparison of
       Average Revenue per kWh by
       Western Rate-setting System for
       the Western Systems
       Coordinating Council (WSCC)
       Region, 1995

       (See figure in printed
       edition.)

    Note:  As discussed later in this appendix, Western is planning to
    reduce rates for the Central Valley Project (CVP).

    Source:  Developed by GAO based on data from Western's 1995 annual
    report and appendix to the 1996 annual report, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

       Figure VII.7:  Comparison of
       Average Revenue per kWh by
       Western Rate-setting System for
       the SPP Region, 1995

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from Western's 1995 annual
    report and appendix to the 1996 annual report, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

       Figure VII.8:  Comparison of
       Average Revenue per kWh by
       Western Rate-setting System for
       the Mid-Continent Area Power
       Pool (MAPP) Region, 1995

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from Western's 1995 annual
    report and appendix to the 1996 annual report, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

       Figure VII.9:  Comparison of
       Average Revenue per kWh by
       Western Rate-setting System for
       the ERCOT Region, 1995

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from Western's 1995 annual
    report and appendix to the 1996 annual report, preliminary
    (unaudited) 1995 IOU data from EIA, and POG data from APPA.

    --------------------
    \6 Power Marketing Administrations:  Cost Recovery, Financing, and
    Comparison to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
    1996).

    \7 The latest data available for all entities except Western were for
    1995; Western had both 1995 and 1996 data.  We used Western's 1995
    data in order to ensure comparability to IOUs and POGs within the
    given time period.  However, it should be noted that Western's
    overall average revenue per kWh decreased from 1.87 in 1995 to 1.65
    in 1996.  All of Western's projects' average revenue per kWh
    decreased in 1996 except Central Arizona (increased from 2.13 to
    2.34), Washoe (increased from .99 to 1.02), and Falcon-Amistad
    (increased from 1.82 to 2.68); all three projects' average revenue
    per kWh were still more than 33 percent below IOUs and POGs in their
    respective regions.  However, in the case of Washoe, average revenue
    per kWh may not be reflective of power production costs because not
    all costs are being recovered through rates.  This also may be the
    situation at several other projects or rate-setting systems with
    financial problems discussed later in this appendix.

    \8 A rate-setting system consists of one or more power projects.

    \9 We used the 1995 NERC configuration because the latest available
    data on average revenue per kWh by NERC region were for 1995.  NERC's
    configuration changed in 1996.  See appendix III for a further
    discussion.

          COST RECOVERY STRUCTURE AND
          INHERENT ADVANTAGES
          CONTRIBUTE TO LOW-COST POWER
    ----------------------------------------------------- Appendix VII:2.2

    As noted in volume 1 of this report and in our September 1996
    report,\10 the three PMAs do not recover all costs associated with
    producing and marketing federal hydropower.  These unrecovered costs
    include net financing costs, Civil Service Retirement System (CSRS)
    pension and postretirement health benefits, certain construction
    costs, power-related costs assigned to incomplete irrigation projects
    at Pick-Sloan, certain environmental costs legislatively precluded
    from recovery, and deferred operations and maintenance (O&M) and
    interest expenses.  As we noted in volume 1 of this report, the PMAs
    are generally following applicable laws and regulations and believe
    that some of these costs, including construction and deferred O&M and
    interest expense, are recoverable through future rates.  If the PMAs
    are required to recover some or all of the above unrecovered costs,
    which we estimate totaled about $185 million for fiscal year 1996,
    their ability to remain competitive may be impaired and the risk of
    future financial loss to the federal government increased.

    The three PMAs have two other key inherent advantages that enhance
    their competitive positions.  First, the three PMAs market power
    generated mainly by hydroelectric plants built decades ago, while
    other utilities are primarily dependent on coal and nuclear
    generating plants.  Table VII.2 shows the contrast between the three
    PMAs and other utilities in the percentage of power coming from
    different generating sources.

                                  Table VII.2

                     Percentage of Net Power Generation for
                       the PMAs and Other Utilities, 1996

                                        Net power generated (percent)
                                   ---------------------------------------
                                     Coal  Nuclear     Gas   Hydro   Other
    -----------------------------  ------  -------  ------  ------  ------
    Three PMAs                      6.6\a        0       0    93.4       0
    Other utilities                  57.5     24.2     9.7     6.1     2.5
    ----------------------------------------------------------------------
    \a A relatively small amount of electricity marketed by Western is
    produced from coal-generating units.

    Source:  Energy Information Administration.

    The hydroelectric plants that generate the power marketed by the PMAs
    have significant cost advantages over coal and nuclear generating
    plants.  For example, the PMAs' hydroelectric plants, many of which
    were built 30 to 60 years ago, had relatively low construction costs.
    To show the relatively low capital cost of the hydropower plants,
    which contributes to the PMAs low average revenue per kWh, we
    compared the three PMAs' investment in utility plant per megawatt of
    capacity for these plants to those of other utilities.  This ratio
    depicts the relative costs of building generating plants.  As shown
    in figure VII.10, the three PMAs have substantially less invested in
    plant than the other utilities.  Southeastern has substantially more
    invested in plant than the other two PMAs because the Russell Project
    has incurred capital costs of more than $500 million as of September
    30, 1996, with no corresponding increase in generating capacity from
    the project's nonoperational portion.

       Figure VII.10:  Investment in
       Utility Plant per Megawatt of
       Generating Capacity, 1995

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from the PMAs' 1995 annual
    reports and 1995 POG and IOU data from EIA.

    Compared to other utilities, the lower investment in PMA-related
    hydroelectric plants is partly the result of lower construction costs
    when these plants were built 30 to 60 years ago compared to more
    recent construction costs.  Unlike the three PMAs and operating
    agencies, IOUs build new capacity to meet the future needs of
    customers.  Many IOU and POG nuclear plants that were completed and
    are operating had significant capital construction costs, which are
    at least partly due to stringent Nuclear Regulatory Commission
    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.\11 Appendix II
    describes the methodology used for computing the ratios in figure
    VII.10.

    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 1995, POGs' fuel costs represented about 11 percent of
    operating revenues, while IOUs' fuel costs represented about 16
    percent of operating revenues.  The PMAs, on the other hand, have the
    benefit of marketing power from hydroelectric plants, which do not
    have an associated fuel cost.\12

    The three PMAs' reliance on hydroelectric generation can also be a
    disadvantage in poor water years.  Because of the reliance on water,
    the three PMAs' revenues can vary considerably and in some years are
    not sufficient to cover operating and interest expenses.  As a
    result, the three PMAs are allowed to defer O&M and interest expense
    payments in years when revenue is not sufficient to cover these
    costs.  Each of the three PMAs has at one time or another had to
    defer O&M and interest expense payments because of poor water
    conditions.\13

    Another key inherent advantage for the three PMAs is that, as federal
    agencies, they generally do not pay taxes.  In contrast, IOUs do pay
    taxes.  According to EIA, in 1995, IOUs paid taxes averaging about 14
    percent of operating revenues.  This average varies significantly
    from state to state due to differing state and local government tax
    laws.  Taxes paid by IOUs include federal and state income taxes,
    real and personal property taxes, corporate franchise taxes, invested
    capital taxes, and municipal license taxes.

    POGs, as publicly owned utilities, typically do not pay income taxes
    because they are units of state or local governments.  However, many
    POGs do make payments in lieu of taxes to local governments.  A
    study\14 of 670 POGs showed that POGs' median net payments and
    contributions as a percent of electric operating revenue for 1994
    were 5.8 percent.  With the exception of the Boulder Canyon Project,
    PMAs generally do not make payments in lieu of taxes to state or
    local governments.  The Boulder Canyon Adjustment Act of 1940
    requires annual payments to the states of Arizona and Nevada.  In
    1995, $600,000, 1.2 percent of the project's operating revenue, was
    paid to these states in lieu of taxes.

    --------------------
    \10 Power Marketing Administrations:  Cost Recovery, Financing, and
    Comparison to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
    1996).

    \11 Our analysis excluded nuclear plants that are mothballed and thus
    provide no capacity while resulting in significant capital costs.
    Mothballed nuclear plants can be either incomplete or completed
    plants that have had construction terminated or have been shut down
    either temporarily or permanently.  Under generally accepted
    accounting principles, these costs are either written off or, if
    deemed allowable by the applicable regulator, are classified as
    "regulatory assets" and included in rates through amortization.
    Inclusion of these regulatory assets would have increased the POG and
    IOU investment.

    \12 As noted in table VII.2, a relatively small amount of electricity
    marketed by Western is produced from coal.

    \13 The flexibility to defer O&M and interest expense enhances the
    three PMAs' ability to compete in a deregulated environment.

    \14 1994 Payments and Contributions by Public Power Distribution
    Systems to States and Local Government, American Public Power
    Association, March 1996.

          MANAGEMENT ACTIONS AND THE
          NATURE OF CUSTOMER CONTRACTS
          CONTRIBUTE TO THE OVERALL
          SOUND COMPETITIVE POSITION
          OF THE THREE PMAS
    ----------------------------------------------------- Appendix VII:2.3

    The three PMAs have taken action to enhance their ability to compete.
    However, because the U.S.  Army Corps of Engineers (Corps) and the
    Bureau of Reclamation (Bureau) operate federal projects, many capital
    and operating costs are beyond the control of the PMAs.

    Southeastern, unlike Southwestern and Western, does not own any
    transmission lines and thus has only a small amount of controllable
    costs.  The main cost under Southeastern's control is staffing, and
    management has held staffing at the PMA steady over the past few
    years.

    At Southwestern, management recently reorganized and began to
    downsize staff to reduce costs.  Southwestern management has also
    begun to benchmark leaders in the electric utility industry.  This
    benchmarking effort is expected to help Southwestern identify ways to
    become more efficient and effective, reduce costs in the future, and
    identify appropriate performance measures that can be used to compare
    Southwestern's performance to its competition.

    At Western, management has undertaken a substantial downsizing of
    staff and initiated other transformation efforts to prepare for
    competition.  According to Western officials, Western is downsizing
    staff by about 25 percent and they expect this effort to result in
    annual savings of about $25 million.  In addition, Western has
    redesigned jobs, instituted manager training, streamlined procedures,
    and continued to work on upgrading its financial management system to
    provide better business information.  Western has also hired a
    benchmarking manager and formed a team to track its position relative
    to its competitors and to develop benchmarking techniques as part of
    its streamlining efforts.

    The nature of the contracts with customers is also currently an
    advantage to the three PMAs.  According to the PMAs, the contracts
    are cost-based, which means that if the PMAs' costs rise they have a
    mechanism to pass those costs along to customers.  These long-term
    contracts, lasting up to 20 years, do not specify rates.  Instead,
    the contracts specify that the customers will pay the rates in effect
    at the time.  If the PMAs raise rates, the customers have the option
    of cancelling their contracts, generally within 1 year of a notice of
    a rate increase.  These contracts are an advantage for the PMAs as
    long as their rates are below market because they can pass rising
    costs along to customers and still be competitive.  However, should
    the three PMAs' rates get close to market rates, the customers'
    ability to cancel contracts could work to the three PMAs'
    disadvantage.

    The PMAs also have certain disadvantages compared to nonfederal
    utilities that could impact their competitiveness.  For example,
    Western is required to recover approximately $1.635 billion related
    to construction costs on completed irrigation facilities.\15 In
    addition, Western is required to recover through rates the cost of
    the Hoover Dam Visitor Center totaling an estimated $124 million.

    --------------------
    \15 Reclamation law provides for Western to repay certain portions of
    capital costs allocated to irrigation purposes which are determined
    to be beyond the ability of the irrigators to repay.

       RISK OF FUTURE LOSSES FROM
       INDIVIDUAL RATE-SETTING
       SYSTEMS/PROJECTS IS PROBABLE
    ------------------------------------------------------- Appendix VII:3

    Although the three PMAs are currently competitively sound overall, we
    identified situations at one or a few projects or rate-setting
    systems at each of the three PMAs that, taken as a whole, indicate
    that it is probable that the federal government will incur some
    future financial losses from one or more of the three PMAs' projects.
    The federal government, to varying degrees, is at risk of losing at
    least some of its investment in six projects/rate-setting systems:
    the Russell Project (Southeastern), Truman Project (Southwestern),
    CVP (Western), Pick-Sloan Program (Western), Mead-Phoenix
    Transmission Line (Western), and Washoe Project (Western).  The
    issues related to each project, grouped by PMA, are discussed below.

          SOUTHEASTERN
    ----------------------------------------------------- Appendix VII:3.1

    To date, about one-half of the cost of constructing the Richard B.
    Russell Project\16 has been excluded from rates paid by power
    customers because the project has never operated as intended.  In
    addition, interest associated with these capital costs is not paid to
    Treasury each year.  Instead, interest--an estimated $29.9 million
    for fiscal year 1996--is capitalized and added to the construction
    work-in-progress (CWIP) balance annually.  It is unclear whether the
    project will ever become fully operational.  However, if the
    nonoperational portion of the project never operates as intended, it
    is probable that the federal government will not recover these
    construction and interest costs.

    This project, located in the Savannah River between Georgia and South
    Carolina, is positioned between two existing dams and was built
    virtually exclusively for the generation of hydropower.  Under the
    Corps' tentative cost allocation, 99 percent of Russell's original
    construction costs and 93 percent of its annual O&M expenses are
    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.\17 The last of the four conventional units
    came on-line in 1986, and the costs associated with these units went
    into Southeastern's costs for recovery.  However, because of
    litigation over excessive fish kills, the four pumping units that
    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 and have not been included in rates.  Interest
    is not paid to Treasury each year on the federal government's
    investment in the nonoperational portion of the project; instead, it
    is capitalized and added to the CWIP balance.  We estimate that the
    balance in the CWIP account was about $518 million at September 30,
    1996.  Since 1996 audited financial statements for Southeastern were
    not available at the time of our review, we estimated the September
    30, 1996, figure by taking the CWIP balance at September 30,
    1995--$488 million--and adding capitalized interest of $29.9 million,
    which we estimated based on the 6.125 percent interest rate
    applicable to the Russell Project.\18

    If the nonoperational portions of the Russell Project are allowed to
    operate commercially in the near future and the costs go into rates,
    Southeastern officials estimate that a rate increase of about 25
    percent to customers of the Georgia-Alabama-South Carolina system
    would be necessary.  This projected rate increase would be necessary
    for two reasons.  First, interest expense related to the
    nonoperational units--which will be more than $30 million in fiscal
    year 1997--would be included in rates rather than capitalized.
    Second, the $518 million currently in CWIP would also be included in
    Southeastern's costs for recovery from power customers.  This
    situation poses a challenge to Southeastern in a competitive
    electricity market.  According to a representative of the
    Southeastern Federal Power Customers, a customer group that
    represents most of Southeastern's customers, power from the
    Georgia-Alabama-South Carolina system would remain competitive even
    after a 25 percent rate increase.  The customer group's view,
    combined with the current production cost advantage\19 of the
    Georgia-Alabama-South Carolina system, of which Russell is a part,
    indicate that the system should be able to remain competitive if the
    nonoperational pumping units are allowed to operate commercially and
    costs are put into rates in the near future.  Under this scenario, we
    believe the risk of loss to the federal government is remote.
    However, the longer the eventual operation of the Russell project is
    delayed, the greater the costs that will have to be recovered through
    rates and the greater the potential impact on rates.  If full
    deployment of the nonoperational units continues to be delayed, at
    some point the price of the power may not be competitive.  We believe
    this poses a reasonably possible risk of future loss to the federal
    government.

    Litigation over the Russell Project is still pending.  Southeastern's
    management believes that the Russell Project is still viable and that
    the litigation will be settled by allowing the project to operate
    commercially.  However, under current policy guidance, if the
    nonoperational units at Russell are not allowed to be put into
    commercial service, the power customers will not be required to repay
    this large federal investment.\20 We believe that under this
    scenario, it is probable that the federal government will lose its
    entire $518 million investment.\21

    --------------------
    \16 The Richard B.  Russell Project was originally named the Trotters
    Shoals Dam.

    \17 The pumping units are designed to allow water, after it has
    passed through generating units, to be pumped back into the reservoir
    during periods of low demand for electricity.  Then, the water can be
    used to produce power during periods of high demand for electricity.

    \18 To estimate the net interest cost, we used the Russell Project
    interest rate of 6.125 rather than Southeastern's overall weighted
    average interest rate on outstanding appropriated debt of 4.4 percent
    for fiscal year 1995.

    \19 As shown in figure VII.2, the Georgia-Alabama-South Carolina
    system's average revenue per kWh for 1995 was 2.88 cents per kWh,
    compared to 4.37 cents and 5.09 cents for IOUs and POGs,
    respectively, in the SERC region.

    \20 This refers to policy guidance contained in Department of Energy
    (DOE) order RA6120.2 through which the recovery of power-related
    costs has been implemented by the Secretary of Energy.

    \21 This $518 million at risk represents about 35 percent of the
    federal government's financial involvement of $1,491 million at
    Southeastern.

          SOUTHWESTERN
    ----------------------------------------------------- Appendix VII:3.2

    A situation similar to Russell exists at the Harry S.  Truman Dam and
    Reservoir, which is located in the Osage River in Missouri.\22
    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.

    The Truman Project has six generating units that could provide
    160,000 kilowatts of capacity and are also designed to operate as
    pumping units.  However, because of design problems and fish kills
    caused 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 power rates the costs associated with the units that
    have not been used commercially.

    The Corps prepared an interim cost allocation for this project which
    accounted for the Truman Project not being fully operational.
    Southwestern petitioned the Federal Energy Regulatory Commission
    (FERC) to have the cost of the nonproducing portion of the assets
    deferred from inclusion in power rates until the project 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 has
    been deferred from recovery through power rates, reducing the total
    to be repaid from $158 million to $127 million.\23 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 and recovered from power customers if the Harry S.  Truman
    facility operates as designed.  Corps officials also told us that the
    Corps is making progress in addressing the design problems.  The
    Corps has modified four of the Truman units and expects to complete
    modifications to the other two units by about mid-January, 1998.
    According to Corps officials, the modification program should
    increase Truman's unit availability.  However, the issue of fish
    kills caused by the pumping units has not been resolved and
    associated capacity has not been restored.  In contrast to the
    situation at Russell, where interest is capitalized on the CWIP
    balance and not paid to Treasury annually, Southwestern has paid
    interest on the $31 million deferral through fiscal year 1996.

    Unless there is a change in the status of the pump-back units, which
    we believe is unlikely given the time frame they have been
    inoperable, it is probable that the federal government will lose the
    $31 million\24 that has been deferred from rates.  However, if the
    pump-back units are allowed into commercial operation and placed into
    rates, we believe that Southwestern's relative cost advantage\25
    indicates that it could absorb the $31 million deferral without a
    significant impact on rates.  Additionally, since Southwestern pays
    annual interest on the deferred Truman costs, the risk is not
    increasing over time due to an increasing balance that would have to
    be repaid if the units become operational in the future.  If the
    units do become operational, we believe the risk of future losses to
    the federal government is remote.

    --------------------
    \22 The Harry S.  Truman Project was originally named the Kaysinger
    Bluff Dam and Reservoir.  Public Law 92-267 changed the name of the
    project to the Harry S.  Truman Dam and Reservoir on May 26, 1970.

    \23 According to Southwestern officials, the deferral does not affect
    O&M costs since all power-related O&M expenses are paid annually.

    \24 This $31 million at risk represents about 5 percent of the
    federal government's financial involvement of $686 million at
    Southwestern.

    \25 As shown in figure VII.3, the Integrated System's (of which
    Truman is a part) average revenue per kWh for 1995 was 1.34 cents per
    kWh, compared to 2.73 cents and 3.48 cents for IOUs and POGs,
    respectively, in the SPP region.

          WESTERN
    ----------------------------------------------------- Appendix VII:3.3

             CENTRAL VALLEY PROJECT
    --------------------------------------------------- Appendix VII:3.3.1

    The Central Valley Project (CVP), which had outstanding appropriated
    debt of about $267 million as of September 30, 1996, and incurred a
    $24 million loss in fiscal year 1996,\26

    faces competition in the California market from low-cost producers
    and others selling surplus power.  Western officials, who market CVP
    power, have responded to this competition by cutting rates by about
    26 percent in fiscal year 1996 and establishing a plan to further
    reduce rates for CVP power by exercising escape clauses in contracts
    to purchase power for resale to CVP customers.\27 According to
    Western officials, the power they are currently purchasing is priced
    higher than CVP's actual production costs, and eliminating the power
    purchases will enable them to reduce CVP's rates and be competitive.
    Western officials said that they have studied the CVP purchase power
    contracts, determined when they can exercise the escape clauses, and
    assessed the resulting rate reductions that can be implemented over
    the next few years.  The officials said they were confident that CVP
    can price its power competitively by eliminating the contracts to
    purchase relatively expensive power.

    A representative of a group of CVP customers confirmed that CVP power
    is presently priced above market and agreed with the Western
    officials' assessment that by eliminating the contracts to purchase
    power CVP can price its power competitively.  The representative
    noted that no customers have cancelled contracts with CVP because
    they believe that the current competitive difficulties can be
    resolved.  However, he also said that the customers that he
    represents would prefer that Western officials in the future focus on
    merely selling CVP's output rather than on entering into contracts to
    purchase power in an effort to meet customers' demand for power.

    Whether Western management's efforts to increase CVP's
    competitiveness will be successful is uncertain.  Moreover, the
    implementation of the Central Valley Project Improvement Act (CVPIA)
    of 1992 is likely to impact the availability of water for power
    generation.  CVPIA strengthened existing fish and wildlife project
    purposes by adding fish and wildlife mitigation, protection, and
    restoration as an authorized purpose of CVP.  This legislation
    emphasized the safeguarding of fish and wildlife.  As a result, less
    water may be available for irrigation, power generation, municipal
    and industrial use, and other purposes.  To the extent that power
    revenues are reduced as a result of the implementation of CVPIA, the
    uncertainty over the repayment of the federal government's investment
    in hydropower facilities at CVP increases.  In addition, according to
    Western officials, when the reallocation of the water occurs, there
    will be a reallocation of substantial costs to power.  Reallocating
    costs to power when power revenues are expected to be reduced would
    further increase the uncertainty surrounding the repayment of the
    federal government's investment in hydropower facilities at CVP.

    Moreover, the amount of water available for hydropower production at
    CVP may be further reduced as a result of changes in the flow of
    water from the Trinity River.  The 1984 Trinity River Basin Fish and
    Wildlife Management Act provided for a program to restore fish and
    wildlife populations to levels that existed just prior to the
    construction of the Trinity River and Lewiston dams in Western's
    Trinity River Division in 1963, which diverted a large portion of the
    Trinity River's water to the Central Valley of California.  We
    believe, and PMA officials have agreed, that the changes in the
    Trinity River water flow resulting from the restoration program may
    increase the risk of loss to the federal government from CVP.  These
    uncertainties, combined with the competition CVP faces, lead us to
    believe that it is reasonably possible that the federal government
    will lose some of its $267 million investment\28 in CVP.

    --------------------
    \26 The $24 million net loss is an accrual-based net loss; CVP was
    able to meet its cash flow requirements in fiscal year 1996.

    \27 According to Western officials, CVP is currently in a formal
    rate-making process for a rate reduction effective October 1, 1997,
    that will reduce the CVP rate to 2.06 cents per kWh.  Western
    officials state that further reductions are planned in fiscal year
    1999 to 1.96 cents per kWh and in fiscal year 2001 to 1.86 cents per
    kWh.

    \28 This $267 million at risk represents about 5 percent of the
    federal government's financial involvement of $5,017 million at
    Western.

             PICK-SLOAN MISSOURI BASIN
             PROGRAM
    --------------------------------------------------- Appendix VII:3.3.2

    The Pick-Sloan Missouri Basin Program (Pick-Sloan) is a comprehensive
    plan to manage the water and hydropower resources of the Missouri
    River Basin.\29 Substantial capital costs for Pick-Sloan hydropower
    facilities and water storage reservoirs have been allocated to
    authorized irrigation facilities that are incomplete and infeasible.
    Western is currently using water to generate power that would have
    been used by irrigators if the irrigation projects had been
    completed.  If the costs had been allocated based on actual use, they
    would have been allocated primarily to power and recovered through
    power rates within 50 years, with interest.  However, as long as the
    costs are allocated to incomplete or infeasible irrigation projects,
    they will likely never be recovered.  Since all but one of the
    irrigation facilities are not expected to be completed, the capital
    costs assigned to the others will not be repaid unless the Congress
    approves a change in the cost allocation methodology used to
    distribute costs to the various program purposes or deauthorizes the
    incomplete or infeasible irrigation facilities.\30 In May 1996,\31 we
    estimated that these capital costs were about $454 million as of
    September 30, 1994.  Since these costs increased by an average of
    nearly $5 million annually between fiscal year 1987 and fiscal year
    1994, we estimate that the costs totaled about $464 million as of
    September 30, 1996.  Under the current repayment criteria, it is
    probable that Western will not be required to recover the principal
    or any interest on the $464 million\32

    investment.

    --------------------
    \29 Pick-Sloan encompasses those parts of Colorado, Iowa, Kansas,
    Minnesota, Missouri, Montana, Nebraska, North Dakota, South Dakota,
    and Wyoming from which water drains into the Missouri River.

    \30 Any changes made regarding the program's power and irrigation
    purposes may 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.

    \31 Federal Power:  Recovery of Federal Investment in Hydropower
    Facilities in the Pick-Sloan Program (GAO/T-RCED-96-142, May 2,
    1996).

    \32 This $464 million at risk represents about 9 percent of the
    federal government's financial involvement of $5,017 million at
    Western.

             MEAD-PHOENIX TRANSMISSION
             LINE
    --------------------------------------------------- Appendix VII:3.3.3

    Another project with questionable financial viability is the
    Mead-Phoenix Transmission Line.  Mead-Phoenix was recently added to
    the Pacific Northwest-Pacific Southwest Intertie (Transmission)
    Project intended to increase power transmission capability between
    central Arizona, southern Nevada, and southern California.  This
    transmission project was a joint venture between Western and 15 other
    utilities and began operation in April 1996.  Western's share of the
    total project's costs is about 34 percent.  Western's portion of the
    cost of the project, including capitalized interest, is about $94.7
    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 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.

    In March 1996 and again in September 1996 testimony before the
    Subcommittee on Water and Power Resources, House Committee on
    Resources,\33 Western officials said that they were aggressively
    marketing the remainder of the line's capacity.  The Western
    officials indicated that if the project does not achieve the level of
    sales assumed in developing the transmission charges, they will
    initiate a new rate process to assure recovery of project costs.
    Western officials said that they were considering blending the
    Mead-Phoenix Transmission Line's rates into the overall rates of the
    Pacific Northwest-Pacific Southwest Intertie Project, of which it is
    a part.  The Western officials asserted that doing this would make
    the Mead-Phoenix costs recoverable and that they had successfully
    done similar types of consolidations in the past.  However, to date,
    the financial results have been discouraging.  From April 1996, when
    it was placed in service, through January 1997, Mead-Phoenix has
    generated revenues of only about $71,319 while incurring O&M and
    interest expenses of nearly $7.3 million, resulting in a net loss of
    about $7.2 million.  The transmission line's poor financial
    performance raises serious questions about its financial viability.
    If the consolidation under consideration cannot be successfully
    implemented, we believe it is probable that the federal government
    will lose at least some of its $94.7 million\34 investment in
    Mead-Phoenix.  Even if the consolidation can be completed, there is
    no indication that the demand for power from the line will increase
    or that Western will be able to successfully market its entire
    transmission capacity, resulting in a reasonably possible risk of
    future loss to the federal government.

    --------------------
    \33 Western Area Power Administration (WAPA) Construction and
    Maintenance Activities and Bureau of Reclamation Power Facilities
    Management, Hearing Before the Subcommittee on Water and Power
    Resources, House Committee on Resources, 104th Cong., 2nd Sess.
    (March 19, 1996), and Statement of Mr.  J.  M.  Shafer,
    Administrator, Western Area Power Administration, United States
    Department of Energy, Hearing Before the Subcommittee on Water and
    Power Resources, House Committee on Resources, 104th Cong., 2nd Sess.
    (September 19, 1996).

    \34 This $94.7 million at risk represents about 2 percent of the
    federal government's financial involvement of $5,017 million at
    Western.

             WASHOE PROJECT
    --------------------------------------------------- Appendix VII:3.3.4

    The Washoe Project (Stampede Powerplant), located in west-central
    Nevada and east-central California, is not generating sufficient
    revenue to cover annual power-related operating expenses and interest
    or to repay the federal investment.  In fact, all required payments
    of annual operating expenses and interest charges have not been made
    to Treasury since the project came on line in 1988, with the deferred
    payments totalling about $4.1 million at the end of fiscal year 1996.
    In addition to the deferred annual expenses and interest payments,
    the Washoe Project had $8.9 million of appropriated debt at September
    30, 1996.

    In January 1997, Western projected that Washoe would have to sell its
    power at a rate of at least 5.7 cents per kWh to cover annual
    operating expenses (excluding depreciation), interest charges, and
    debt repayments.  This projection is substantially different from the
    Western officials' January 1996 projection that Washoe power would
    have to be sold at a rate of at least 11 cents per kWh to cover these
    costs.  Both projections are substantially higher than the Washoe
    average revenue per kWh of energy sales of 1.02 cents in fiscal year
    1996.  The change in projection by Western is due to the reallocation
    of some Washoe costs from power to fish hatcheries protection which,
    according to Western officials, does not require recovery through
    rates from power customers.  We believe that the costs reallocated
    are still power-related costs and remain a net cost to the federal
    government.  As with the Mead-Phoenix Transmission Line, Western
    officials said that they were considering combining the Washoe
    Project power with the Central Valley Project and establishing a
    blended rate that would recover all costs associated with both
    projects, noting that they had successfully carried out similar types
    of consolidations in the past.  However, CVP is itself a problem
    project, which would make the risk to the federal government from
    Washoe reasonably possible even after a consolidation.

    We concur with Western, which stated in its 1995 annual report that
    it is unlikely that Washoe will be able to generate sufficient
    revenues to repay the federal investment.  Moreover, we believe that
    as a stand-alone rate-setting system, Washoe will continue to incur
    annual operating losses and it is probable that the federal
    government will not recover the $13 million\35 of appropriated debt
    and deferred payments.

    --------------------
    \35 This $13 million at risk represents about 0.3 percent of the
    federal government's financial involvement of $5,017 million at
    Western.

    RISK ASSESSMENT FOR THE BONNEVILLE
    POWER ADMINISTRATION
    ======================================================== Appendix VIII

    The Bonneville Power Administration (BPA) had over $17 billion of
    debt and about $766 million of interest expense as of and for the
    year ended September 30, 1996.  These high fixed costs limited BPA's
    flexibility to lower rates and significantly contributed to BPA's
    loss of sales to its preference and industrial customers in recent
    years.  However, as a result of existing customer contracts, a
    memorandum of agreement (MOA) limiting fish and wildlife mitigation
    costs, and currently large financial reserves, we believe that the
    risk of any significant loss to the federal government from BPA is
    remote through fiscal year 2001.  After fiscal year 2001, we believe
    that expiration of customer contracts, significant risks from market
    uncertainties, BPA's high fixed costs, and substantial upward
    pressure on other expenses make the risk of loss to the federal
    government reasonably possible.  This risk will begin to decline
    after fiscal year 2012, all else being equal, if BPA pays off its
    nonfederal debt as scheduled.  One small project that would have
    served BPA, Teton Dam, represents a probable financial loss to the
    federal government.

       THE FEDERAL GOVERNMENT'S
       FINANCIAL INVOLVEMENT
    ------------------------------------------------------ Appendix VIII:1

    The federal government has substantial direct and indirect financial
    involvement in the activities of BPA.  The direct involvement relates
    to BPA's appropriated debt, Treasury bonds, and irrigation debt.\1
    For all three categories of direct debt, BPA is repaying the federal
    government.  The federal government's indirect financial involvement
    relates to what BPA calls its nonfederal project debt ("nonfederal
    debt"),\2 which is due primarily to construction of nuclear projects
    of the Washington Public Power Supply System.  Table VIII.1 details
    the amounts of direct and indirect debt by type.

                                  Table VIII.1

                       The Federal Government's Financial
                     Involvement in BPA as of September 30,
                                      1996

                             (Dollars in billions)

                                                Financial involvement
                                            ------------------------------
    Description                             Direct    Indirect       Total
    --------------------------------------  ------  ----------  ==========
    Appropriated debt                         $6.8                    $6.8
    Treasury bonds                             2.5                     2.5
    Irrigation debt                            0.8                     0.8
    Nonfederal debt                                       $7.1         7.1
    ======================================================================
    Total                                    $10.1        $7.1       $17.2
    ----------------------------------------------------------------------

    --------------------
    \1 Aid to Irrigation (which we refer to as irrigation debt) is the
    legal obligation to repay costs incurred to construct federal
    irrigation projects that are determined by law to be beyond the
    irrigators' ability to repay.

    \2 BPA used its contracting authority to acquire all or part of the
    generating capability of power projects of the Washington Public
    Power Supply System, a municipal corporation of the state of
    Washington.  Under these agreements, BPA contracts to pay all or part
    of the annual project budgets, including debt service, whether or not
    the projects are completed.  BPA does not have the authority to
    borrow from nonfederal sources or to construct power generating
    facilities.

          DIRECT FINANCIAL INVOLVEMENT
    ---------------------------------------------------- Appendix VIII:1.1

    BPA's appropriated debt consists of appropriations primarily used to
    construct the generating and transmission projects from which BPA
    markets power.  The total of $6.85 billion of appropriated debt as of
    September 30, 1996, carried a weighted-average interest rate of about
    3.5 percent.  Retroactively effective to the first day of fiscal year
    1997, the Omnibus Consolidated Rescissions and Appropriations Act of
    1996 authorizes the restructuring of this debt, reducing the
    principal to an estimated $4.29 billion and increasing the associated
    interest rate to approximately 7.1 percent.  According to BPA's 1996
    final rate proposal, the transaction "is intended to permanently
    eliminate subsidy criticisms directed at the relatively low interest
    rates assigned to historic Federal Columbia River Power System
    appropriations."\3 The dates when this debt is due, which extend
    through fiscal year 2046 and average about 26 years remaining, are
    not changed by the legislation.

    According to BPA, the legislated restructuring is such that the
    present value of the new (revised) appropriated principal is equal to
    the present value of the principal and interest payments scheduled
    before the restructuring, plus $100 million.  The $100 million is
    spread pro rata among all outstanding appropriations and results in
    an increase of $100 million in present value terms on related debt
    service payments.  The resulting new principal amounts are assigned
    interest rates based on prevailing Treasury yield curve interest
    rates at the time of the transaction.  With the exception of the
    additional $100 million and the interest on it, we believe that in
    substance this transaction does not change the government's future
    net financing cost\4 and, even if implemented in fiscal year 1996,
    would not have changed the $377 million estimated net financing cost
    on BPA appropriated debt for fiscal year 1996.

    Beginning in fiscal year 1997, all BPA's appropriations are required
    by law to be assigned prevailing Treasury yield curve interest rates.
    The Refinancing Act also requires that BPA's Administrator offer to
    include in all future and existing contracts for the sale of electric
    power, transmission, or related services terms that ensure that
    ratepayers pay no more principal and interest on the restructured
    appropriations than the act prescribes.

    BPA also had about $2.5 billion of medium- and long-term debt held by
    Treasury in the form of BPA bonds.  BPA's Treasury bond borrowing
    stems from authority granted in the Federal Columbia River
    Transmission System Act of 1974, as amended, that allows BPA to
    borrow up to $3.75 billion directly from Treasury.  The $3.75 billion
    consists of two separate borrowing authority limits:  $1.25 billion
    for conservation and renewable energy investments and $2.5 billion
    for transmission and other capital investments.\5

    In borrowing these funds, BPA sells bonds to Treasury at interest
    rates set by Treasury.  Interest rates are determined based on
    comparable debt with similar terms issued by U.S.  government
    corporations.  The rates are adjusted to reflect the cost of specific
    features of BPA's bonds, such as the maturity date and the ability to
    call the bonds.  The weighted-average interest rate on this debt as
    of September 30, 1996, was about 7.5 percent.  The 7.5 percent
    interest rate results from the combination of BPA refinancing its
    Treasury bonds and/or retiring these bonds prior to their maturity.
    BPA paid a call premium on this refinancing that was established by
    Treasury prior to issuance of the bonds.

    In addition to appropriated debt and Treasury bonds, BPA is
    responsible for repaying irrigation-related construction costs on
    certain Bureau of Reclamation irrigation facilities, as provided by
    project-specific authorizing legislation.\6 We refer to this
    repayment responsibility as irrigation debt.  BPA's irrigation debt
    relates to its requirement to pay for irrigation capital costs that
    are determined to be beyond the ability of the irrigation water users
    to repay.  Irrigation debt is generally due up to 60 years after
    completion of the construction of the irrigation facilities and is to
    be repaid at zero-percent interest.  The estimated balance of this
    obligation is $841 million as of September 30, 1996.  BPA's first
    payment of $25 million to the Treasury for irrigation debt is
    currently planned to be made in fiscal year 1997; an additional
    payment of $10 million is due in fiscal year 2001.  The remaining
    $806 million is due after fiscal year 2001.  Although irrigation debt
    is scheduled to be recovered from power revenues, BPA does not view
    irrigation debt as a power cost.  Instead, BPA discloses this debt in
    the notes to the financial statements under "Commitments and
    Contingencies." However, if BPA recovers these amounts through its
    rates, these costs and revenues will be reflected in its financial
    statements.  To the extent irrigation debt is recovered through
    electricity rates, BPA's power customers are subsidizing irrigators.

    The federal government would incur a future loss on direct financial
    involvement if BPA failed to make payments on federal debt.

    --------------------
    \3 BPA is part of the Federal Columbia River Power System (FCRPS),
    which also includes the power-related operations of the Corps and the
    Bureau.  BPA is responsible for marketing power from FCRPS.

    \4 However, if BPA repays the principal before it is due, and the
    federal government's cost of money has declined, the federal
    government will experience a decrease in cash flow and a resulting
    increase in net cost.

    \5 BPA treats the amount of borrowing authority that it has
    "deferred" as part of its financial reserves.  Deferred borrowing is
    created when BPA uses operating revenues to finance capital
    expenditures in lieu of borrowing.  This temporary use of
    cash-on-hand instead of borrowed funds creates the ability in future
    years to borrow money, when fiscally prudent, to liquidate revenue
    funded activities.

    \6 Project-specific authorizing legislation determines how the costs
    of constructing reclamation projects are allocated and how repayment
    responsibilities are assigned among the projects' beneficiaries.
    Collectively, the Reclamation Project Act that is generally
    applicable to all projects and the statutes authorizing individual
    projects are referred to as reclamation law.  In implementing
    reclamation law, the Bureau of Reclamation is guided by its
    implementing regulations, administrative decisions of the Secretary
    of the Interior, and applicable court cases.  The Columbia Basin
    Project Act provides for BPA to use its power revenues to repay
    Treasury a certain portion of the capital costs allocated to
    completed irrigation facilities that are determined by the Secretary
    of the Interior to be beyond the ability of the irrigators to repay
    (irrigation assistance).

          INDIRECT FINANCIAL
          INVOLVEMENT
    ---------------------------------------------------- Appendix VIII:1.2

    BPA had nonfederal debt of about $7.1 billion at September 30, 1996.
    This debt resulted from BPA's use of its contracting authority to
    acquire all or part of the generating capability of power projects of
    other entities.  Under this arrangement, BPA contracts to pay for all
    or part of the annual project budgets, including debt service,
    whether the projects are completed or not.  Approximately $4.24
    billion of this total relates to three nonoperational and canceled
    nuclear projects, and an additional
    $2.54 billion to one operating nuclear plant.  The remaining amount
    of about $321 million is for financing of small hydroelectric
    projects and conservation measures.  The nonfederal debt is not
    explicitly guaranteed by the federal government; however, the
    financial community views this debt as having an implicit federal
    guarantee.

    For this indirect involvement, the federal government would incur
    future losses for unreimbursed costs related to any actions it took
    to prevent default on nonfederal debt service payments or breach of
    contract on nonfederal debt by BPA.

       RISK OF LOSS FROM BPA IS REMOTE
       THROUGH FISCAL YEAR 2001
    ------------------------------------------------------ Appendix VIII:2

    As a result of existing customer contracts, an MOA that put a ceiling
    on fish and wildlife mitigation costs and large financial reserves,
    we believe that the risk of any significant loss to the federal
    government from BPA is remote through fiscal year 2001.

          CUSTOMER CONTRACTS
    ---------------------------------------------------- Appendix VIII:2.1

    BPA has succeeded in signing most of its preference customers and
    industrial customers to contracts through fiscal year 2001.
    According to BPA, its new contracts make more extensive use of "take
    or pay" provisions than the old contracts.  Such provisions require
    the customer annually to buy a specified, minimum amount of
    electricity at a set price.  The contracts provide a substantial
    economic certainty to BPA in terms of the revenues that can be
    expected through fiscal year 2001.  BPA projects that firm power
    sales to these customers will secure $1.14 billion annually through
    fiscal year 2001, or approximately 63 percent of each year's total
    power revenue.  The nature of these contracts and the certainty they
    provide strongly mitigate the possibility of financial loss to the
    federal government through fiscal year 2001.

          FISH AND WILDLIFE COSTS
    ---------------------------------------------------- Appendix VIII:2.2

    BPA bears substantial financial responsibility for measures to
    protect fish and wildlife populations and to mitigate damage to
    Pacific Northwest fish stocks affected by the construction and
    operation of the Federal Columbia River Power System.  These costs
    include (1) outlays to fund operating and maintenance and capital
    costs for fish and wildlife mitigation and protection programs and
    (2) revenues BPA has forgone and related costs it has incurred
    because of restrictions on the operations of the hydroelectric dams,
    which generate the power marketed by BPA.  For example, BPA's total
    fish and wildlife costs in fiscal year 1996 were $278 million,
    including outlays of $176 million to fund fish and wildlife programs
    and $102 million in forgone revenues and related costs.

    Escalation of these costs in recent years has placed considerable
    financial strain on BPA.  Figure VIII.1 shows the trend of these
    costs, which include both funding outlays for fish and wildlife
    programs and revenues forgone because water was used for fish and
    wildlife purposes rather than hydropower production.

       Figure VIII.1:  BPA Fish and
       Wildlife Costs, Fiscal Years
       1990-1996

       (See figure in printed
       edition.)

    As figure VIII.1 shows, these costs have increased significantly over
    time, from $146 million in fiscal year 1990 to $399 million in fiscal
    year 1995.  Fiscal year 1996 saw a decrease in costs to $278 million,
    primarily because a large volume of water was available that year for
    both fish and wildlife mitigation and power production.

    To address the problem of rising fish and wildlife-related costs, BPA
    entered into a MOA with the National Marine Fisheries Service, the
    U.S.  Army Corps of Engineers, the Bureau of Reclamation, and the
    U.S.  Fish and Wildlife Service in September 1996.  The MOA limited
    BPA's fish and wildlife related funding responsibility and helped
    make it possible for BPA to offer contracts to its preference
    customers for fiscal years 1997 through 2001 at a reduction that
    averaged 13 percent, in comparison to rates prevailing in fiscal year
    1996.

    The MOA's annual total cost includes an agreement to limit actual
    funding outlays for fish and wildlife costs to an average of $252
    million per year.  In addition, BPA agreed to absorb additional costs
    in the form of forgone hydropower revenues resulting from water being
    used for fish and wildlife-related purposes and the cost of power
    purchases made necessary because of the fish protection effort.

    Another factor adds to BPA's ability to control its fish and
    wildlife-related costs.  In each year since the passage of the
    Pacific Northwest Electric Power Planning and Conservation Act
    (Northwest Power Act) (Pub.  Law No.  96-501) in 1980, BPA has funded
    fish and wildlife related costs through rates.  According to BPA, it
    had not recouped the portion of such expenditures that are
    attributable to the nonpower portion of the federal system's multiple
    purpose projects.  Starting with fiscal year 1994, BPA began
    recouping these costs by taking credits against its annual Treasury
    payment.  The credits BPA has taken were $19 million for fiscal year
    1994, $56 million for fiscal year 1995, and $31 million for fiscal
    year 1996.\7

    The MOA describes a "Fish Cost Contingency Fund," which is available
    to BPA in certain situations.  The fund consists of $325 million in
    credits that BPA is authorized to take against amounts otherwise
    payable by BPA to the Treasury.  The amount in the fund is BPA's
    estimate of the portion of fish and wildlife-related expenditures
    that BPA made in the years prior to 1994 that were related to the
    nonpower purposes of the dams.  BPA has not yet found it necessary to
    use the contingency fund.  According to BPA, the MOA expires in
    fiscal year 2001, but the fund does not.

    The MOA envisions the possibility that unforeseen events may make
    more fish and wildlife mitigation funding necessary, but does not
    specify what the funding source will be.  It states that the parties
    to the MOA, along with the Pacific Northwest Electric Power and
    Conservation Planning Council\8 and the region's Indian tribes,
    should attempt to reach agreement on how additional funding is to be
    provided.  If no agreement can be reached, the MOA provides that BPA
    is to recommend a funding mechanism to the Office of Management and
    Budget and the Council on Environmental Quality.

    It is uncertain whether the MOA will be renewed or extended before it
    expires in fiscal year 2001.  As long as this MOA remains in force,
    it provides BPA with protection against fish and wildlife-related
    costs exceeding the limit established in the agreement.

    --------------------
    \7 The amounts for fiscal years 1995 and 1996 are estimates.  BPA is
    in the process of determining what the final amounts will be.

    \8 The Northwest Power Act established the Pacific Northwest Electric
    Power and Conservation Planning Council to provide guidance to BPA in
    its power planning and fish and wildlife program and other
    responsibilities.  The Council consists of members appointed by the
    primary states served by BPA.

          FINANCIAL RESERVES
    ---------------------------------------------------- Appendix VIII:2.3

    BPA currently has substantial financial reserves.\9 The agency had a
    $278 million cash and deferred borrowing authority balance at the end
    of fiscal year 1996.  Because water for the hydropower system has
    been plentiful, BPA expects to have a cash and deferred borrowing
    authority balance at the end of fiscal year 1997 of about $400
    million.  In addition, the $325 million Fish Cost Contingency Fund
    discussed previously provides a supplementary financial reserve.
    These reserves provide BPA with the flexibility to deal with its
    operating risks.

    However, BPA's reserves could be decreased by factors such as lawsuit
    settlements, and BPA's reserve levels have, in the past, varied
    considerably over time.  An example of this was the decrease from an
    $877 million balance at the end of fiscal year 1991 to a $221 million
    balance at the end of fiscal year 1993.  Also, deferred borrowing
    authority may be useful in the short term to provide liquidity, but,
    since it results in additional debt, is not a long-term solution to
    financial difficulty.

    --------------------
    \9 BPA financial reserves include cash and deferred Treasury
    borrowing authority, and the Fish Cost Contingency Fund constitutes a
    supplementary financial reserve, available in specified emergency
    situations.  Deferred borrowing authority is similar to an unused
    line of credit.

       RISK OF LOSS IS REASONABLY
       POSSIBLE AFTER FISCAL YEAR 2001
    ------------------------------------------------------ Appendix VIII:3

    Because of risks from the expiration of customer contracts, market
    uncertainties, BPA's high fixed costs, and upward pressure on other
    expenses, the risk of loss to the federal government increases
    significantly after fiscal year 2001.  Despite a number of factors
    that mitigate this risk, we believe it is reasonably possible the
    federal government will incur losses relative to BPA after fiscal
    year 2001.

          CUSTOMER CONTRACTS EXPIRE IN
          FISCAL YEAR 2001
    ---------------------------------------------------- Appendix VIII:3.1

    In fiscal year 2001, nearly all of BPA's power contracts with
    customers will expire.  In that year, BPA projects firm power
    revenues from all customers totaling $1.58 billion.  In the following
    year, should no contract renewals occur, only $286 million in firm
    power revenues will be contractually committed--a reduction of 82
    percent.  BPA has acknowledged this risk and is attempting to
    construct new contracts and have them signed before the current
    contracts expire.  This effort is the result of a December 1996 study
    called the Comprehensive Review of the Northwest Energy System
    (Comprehensive Review).

    The Comprehensive Review was conducted at the direction of the
    governors of the four primary states that BPA serves and included an
    evaluation of what BPA's role should be in the Pacific Northwest
    energy market.  One of the study's recommendations was that BPA
    devise "subscription contracts." These contracts would be long-term
    (5 to 20 years) and would offer benefits to "subscribers"--such as
    the ability to purchase from BPA at cost when costs are below market
    levels--and would help assure BPA's financial stability.  BPA and its
    customers are participating in a work group that is developing the
    subscription contract concept.  BPA's goal is to have the
    subscription process implemented and new contracts signed before the
    existing contracts expire.

    If a significant amount of BPA's power is not contractually obligated
    in the future, BPA could be subject to considerable financial risk.
    If customers can find cheaper power sources, they might opt to leave
    BPA.  The agency could find itself in a situation in which it has no
    guaranteed, stable market for its power, and could be unable to sell
    power on the open market at prices that allow full cost recovery.

          SIGNIFICANT RISK FROM MARKET
          UNCERTAINTIES
    ---------------------------------------------------- Appendix VIII:3.2

    BPA faces substantial risk from the uncertainties of the wholesale
    electricity marketplace.  Among these risks are the future production
    cost of gas-fired generation plants, the existence of surplus
    electric power in the geographic area in which BPA operates, and the
    effects of retail open access on BPA and its customers.

             NATURAL GAS PRODUCTION
             COSTS AND SURPLUS POWER
    -------------------------------------------------- Appendix VIII:3.2.1

    One of the key market uncertainties that will determine whether
    cheaper power will be available in the future is the production cost
    of gas-fired generation plants.  This generation source has become
    increasingly competitive due to low natural gas prices and improving
    gas turbine technology.  Natural gas prices in the Pacific Northwest
    are low due to several factors, including a large supply coming from
    Canada.  Also, recent technological advances have improved the
    efficiency of gas turbines by more than 50 percent.  According to
    BPA, natural gas-generated power has driven down the price of
    wholesale electricity and resulted in customers obtaining some of
    their power at rates well below BPA's current rate.

    BPA officials stated that natural gas prices will be one of the most
    important variables regarding future competitiveness.  In its "Future
    Focus" planning effort, BPA researched available studies predicting
    future gas prices and discovered that there is a wide range of
    predictions.  BPA selected what it deemed to be the most credible
    high-range and low-range predictions for its planning purposes.  BPA
    concluded that it could remain competitive--even assuming low prices
    of gas in the future--if it can lower its costs to 2 cents per
    kilowatthour (kWh).  BPA's Administrator told us that achieving this
    cost level is a primary organizational goal.

    The price of natural gas was a primary variable in a 1996 study done
    for BPA.  The study used three gas price escalation scenarios:  base,
    low, and high.  The base scenario assumed that gas prices would
    increase at the rate of inflation.  The low-price scenario assumed
    that gas prices would be constant in nominal dollars through fiscal
    year 2000 and would increase at the rate of inflation thereafter.
    The high-price scenario assumed that gas prices would increase at 1.8
    percent per year above the rate of inflation.  The study generally
    found that BPA would not experience stranded costs\10 if gas prices
    escalated as assumed in the base and high scenarios.  However, under
    the low-price scenario, BPA would have stranded costs.  In that
    scenario, gas prices were assumed to be low, technology was assumed
    to make new lower-cost gas plants feasible, and the demand for
    electricity was assumed to be low.

    According to BPA, surplus power, partially caused by record high
    river conditions and high hydropower production in the Pacific
    Northwest, is also driving down the price of wholesale power.
    Because utilities still are able to pass on fixed costs to captive
    retail customers, surplus wholesale power is being sold on a marginal
    cost basis.  According to BPA, other utilities and power brokers are
    offering wholesale power for as low as 1.5 cents per kWh, which is
    lower than BPA's price for sales of comparable products at the
    current firm rate of 2.14 cents per kWh.  It is uncertain whether
    surplus power and low cost natural gas generation will continue to
    drive down wholesale power prices after fiscal year 2001.

    --------------------
    \10 As defined by the Federal Energy Regulatory Commission (FERC), a
    stranded cost is any legitimate, prudent, and verifiable cost
    incurred by a public or transmitting utility that is no longer
    economically viable in a competitive wholesale environment.

             EFFECTS OF RETAIL OPEN
             ACCESS
    -------------------------------------------------- Appendix VIII:3.2.2

    The possibility of retail open access adds to future uncertainty
    about the competitive environment in which BPA and its customers will
    operate.  BPA sells wholesale power to utilities, which then resell
    it on a retail basis.  Retail open access--which would provide retail
    customers the freedom to choose among suppliers--could result in
    BPA's customers being uncertain about the size of their own future
    retail sales.  This uncertainty would make it unattractive for
    customers to sign long-term contracts with BPA until they are
    reasonably assured of a stable, predictable retail customer base.
    However, even without long-term contracts, BPA is likely to remain a
    major supplier.  All four states that constitute BPA's primary
    service area are considering some form of retail open access, and,
    under current law, retail open access will be decided on a
    state-by-state basis.  However, the Congress is considering various
    proposals regarding the approach to retail open access that would be
    applied nationally.

             BPA'S SUBSTANTIAL
             FINANCING COSTS CONTINUE
    -------------------------------------------------- Appendix VIII:3.2.3

    BPA faces substantial risk beyond fiscal year 2001 because a large
    portion of its operating costs are fixed and therefore beyond
    management's control.  The consequence of this lack of financial
    flexibility was demonstrated in fiscal years 1994 and 1995, when
    decreasing electricity prices resulted in BPA losing sales to other
    providers.  Interest expense is BPA's second-largest expense (behind
    its operations and maintenance expense) and represents BPA's largest
    fixed cost.  In fiscal year 1996, BPA paid approximately $766 million
    in interest expense on its $17.2 billion in debt.  This level of
    expense means that BPA used 32 percent of its revenues in fiscal year
    1996 to pay the interest on its debt.  As shown in figure VIII.2,
    BPA's financing costs to revenue ratio is higher than those of
    investor-owned utilities (IOUs) and publicly-owned generating
    utilities (POGs), whose ratios were 15 and 18 percent (on a
    nationwide basis), respectively.

       Figure VIII.2:  Financing Costs
       as a Percentage of Revenues for
       BPA, IOUs, and POGs

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from BPA's 1996 annual report
    and national 1995 POG and IOU data from the Energy Information
    Administration (EIA).

    BPA's relatively high financing costs mean that it has less
    flexibility than IOUs and POGs to reduce costs and hence lower rates
    to respond to competitive pressures.  For example, BPA officials told
    us that it lost customers in fiscal years 1994 and 1995 as a result
    of its inability to lower rates in response to falling electricity
    prices in the Pacific Northwest.

    It is important to note that a substantial portion of BPA's debt and
    interest expense relates to the construction of nonoperating nuclear
    plants.  BPA has over $4.2 billion invested in these plants.
    Interest expense associated with these plants amounted to over $230
    million in fiscal year 1996.  This relatively high level of interest
    expense can be expected to continue for the foreseeable future,
    greatly limiting BPA's ability to react to falling electricity
    prices.  Also, new borrowing and the potential need to refinance
    BPA's Treasury bonds as they mature could expose BPA to the risk of
    rising interest rates and even higher financing costs.

    BPA is scheduled to have nearly all of its nonfederal debt, including
    the debt associated with nonoperating nuclear plants, paid off by
    fiscal year 2019.  Substantial decreases in scheduled nonfederal debt
    servicing begin in fiscal year 2013.  Specifically, these debt
    service costs are expected to decrease from an average of about $570
    million annually from fiscal years 1997 through 2012, to an average
    of about $304 million annually from fiscal years 2013 through 2018.
    In fiscal year 2019, BPA's scheduled debt service payment declines to
    less than $3 million and decreases further in the following years.
    If BPA is able to make these payments as scheduled, all else being
    equal, its fixed financing costs would be more in line with those of
    its competitors.  This would result in a reduction of risk to the
    federal government over time.

             BPA FACES UPWARD PRESSURE
             ON OTHER EXPENSES AFTER
             FISCAL YEAR 2001
    -------------------------------------------------- Appendix VIII:3.2.4

    Several factors combine to increase the financial pressure faced by
    BPA in the period beyond fiscal 2001.  Among them are the expiration
    of the fish and wildlife MOA, the inclusion of the full cost of
    pension and postretirement health benefits in rates, payments of
    irrigation debt, payments to the Colville Tribes, and possible
    payments to settle a lawsuit.  Taken individually, these factors may
    not place substantial pressure on BPA's ability to remain
    competitive, but in combination they could have this effect.

    It is uncertain whether an agreement similar to the current MOA that
    stabilizes fish and wildlife costs will be entered into after the
    present one expires.  Absent this agreement, BPA is at risk if costs
    escalate beyond the MOA limits after fiscal year 2001.

    BPA also faces substantial new or additional costs after fiscal year
    2001.  First, it plans to implement a phased-in approach to
    recovering the full cost of pension and postretirement health
    benefits in fiscal year 1998, but will defer full recovery until
    fiscal year 2002 when $55 million will be due.  To completely recover
    obligations for fiscal years 1998 through 2001, an additional $35
    million will be due in fiscal year 2003.  Other costs that will be
    incurred over the several decades after fiscal year 2001 include an
    estimated $806 million of irrigation debt and BPA's estimated $396
    million in payments to the Confederated Tribes of the Colville
    Reservation for its share of Grand Coulee Dam revenues.  The payments
    to the Tribes are to be made annually, and are based on an
    agreed-upon range of prices for electricity and the Grand Coulee
    Dam's power generation for each year.

    The pending lawsuit against BPA by Tenaska Washington Partners, II
    L.P.  (Tenaska) could result in additional financial pressure on BPA.
    In 1994, BPA and Tenaska entered into a power purchase agreement
    under which Tenaska was to build and BPA was to purchase the output
    of a combustion turbine generating plant.  In 1995, BPA gave notice
    to Tenaska that "its purpose in acquiring the resource had been
    frustrated as a result of the loss of a significant portion of the
    load which the resource had been acquired to serve and because the
    resource could not operate as intended within the Federal System
    because of operational requirements imposed by the 1995 (Endangered
    Species Act) Biological Opinion after the power purchase agreement
    was executed."

    Tenaska and Chase Manhattan Bank (which had arranged the financing
    for the canceled project) sued BPA for breach of contract.  BPA paid
    $115 million to Chase in settlement of Chase's claim.  BPA has
    entered binding arbitration with Tenaska to settle its claim.  The
    $115 million payment to Chase is to be offset by any award to
    Tenaska.  According to the Notes to the Financial Statements in BPA's
    1996 annual report, BPA believes that the factual and legal
    assertions by Tenaska in support of its $1.125 billion claim are
    without merit.  However, if the arbitration of this lawsuit results
    in a judgment against BPA in an amount substantially in excess of
    $115 million, it would increase the risk of financial loss to the
    federal government.

          MITIGATING FACTORS REDUCE
          LONG-TERM PROBABILITY OF
          LOSS
    ---------------------------------------------------- Appendix VIII:3.3

    Several factors mitigate the federal government's risk of loss from
    BPA.  These factors include inherent cost advantages, management
    actions that reduce operating costs, and BPA's extensive transmission
    system.  Because of these factors, we believe the risk of loss to the
    federal government after fiscal year 2001 is reduced, but is still
    reasonably possible.  However, beginning in fiscal year 2013,
    nonfederal debt levels are scheduled to decline substantially.  If
    BPA pays off its nonfederal debt, all else being equal, its fixed
    financing costs would be more in line with those of its competitors.
    This would reduce the risk to the federal government.

             COST RECOVERY STRUCTURE
             AND INHERENT ADVANTAGES
             CONTRIBUTE TO LOW-COST
             POWER
    -------------------------------------------------- Appendix VIII:3.3.1

    As shown in figure VIII.3, in 1995 BPA's average revenue per kWh was
    more than 15 percent lower than IOUs and POGs in the primary North
    American Electric Reliability Council (NERC)\11 regions in which BPA
    operates.  Although BPA's average cost of production is substantially
    below that of other utilities, as indicated by its favorable average
    revenue per kWh ratio, it is currently facing significant competition
    from electricity that is being sold at marginal costs.  If the supply
    of surplus power subsides and natural gas prices rise, which BPA
    believes will happen, BPA's low average production costs should
    significantly improve its long-term competitive position.

       Figure VIII.3:  Average Revenue
       per kWh of Wholesale Power
       Sold, 1995 (Revenues in cents)

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from BPA's 1996 annual
    reports, preliminary (unaudited) 1995 IOU data from EIA, and POG data
    from the American Public Power Association (APPA).

    BPA has inherent cost advantages compared to nonfederal utilities.
    As discussed in volume 1 of this report, in 1996 BPA did not charge
    through to rates nearly $400 million of costs associated with
    producing and marketing federal power.  These unrecovered power costs
    give BPA a significant competitive advantage compared to nonfederal
    utilities.

    BPA's costs are also minimized by the fact that it markets power
    generated mainly by hydroelectric plants built 30 to 60 years ago,
    while other utilities are primarily dependent on coal and nuclear
    generating plants.  Table VIII.2 shows the contrast between BPA and
    other utilities in the percentage of power coming from different
    generating sources.

                                  Table VIII.2

                    Percentage of Net Generation for BPA and
                             Other Utilities, 1996

                                     Coal  Nuclear     Gas   Hydro   Other
    -----------------------------  ------  -------  ------  ------  ------
    BPA                                \0      7.4       0    92.6       0
    Other utilities                  57.5     24.2     9.7     6.1     2.5
    ----------------------------------------------------------------------
    Source:  BPA for BPA data, EIA for other utilities data.

    The hydroelectric plants that generate the power marketed by the BPA
    and the other PMAs have significant cost advantages over coal and
    nuclear generating plants, which are used to generate over 81 percent
    of the electricity in the United States.  For example, BPA's
    hydroelectric plants, which were built decades ago, had relatively
    low construction costs.  To show the relatively low capital cost of
    the hydropower plants, which produced nearly 93 percent of the power
    marketed by BPA in fiscal year 1996, we compared BPA's investment in
    utility plant per megawatt of capacity for these plants to those of
    IOUs and POGs nationwide.  As shown in figure VIII.4, BPA has
    invested less in plant per megawatt of generating capacity than the
    other utilities.\12 Appendix II describes the methodology used for
    computing the ratios in figure VIII.4.

       Figure VIII.4:  Investment in
       Utility Plant per Megawatt of
       Generating Capacity

       (See figure in printed
       edition.)

    Source:  Developed by GAO based on data from BPA's 1996 annual report
    and 1995 IOU and POG data from the EIA.

    BPA's low investment in utility plant per megawatt of generating
    capacity contributes to BPA's relatively low average revenue per kWh,
    as shown in figure VIII.3.  As discussed earlier, because of BPA's
    investment in nonoperational nuclear plants, BPA's overall production
    costs are higher than would be the case in the absence of these
    investments.  This is because BPA has invested over $4.2 billion in
    these nonoperating plants, which, while producing no marketable
    power, incur substantial interest expense.  BPA's investment in
    utility plant per megawatt of generating capacity, as shown in figure
    VIII.4, would be substantially lower--$630,000 per megawatt--if the
    $4.2 billion of nonoperating plant investments were excluded.

    Another major reason that hydroelectric plants result in lower
    production costs is the cost of fuel.  This is particularly important
    when comparing hydroelectric plants to coal plants because 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 cost as coal.  In 1995, POGs' fuel costs represented about 11
    percent of operating revenues, while IOUs' fuel costs represented 16
    percent of operating revenues.  BPA, on the other hand, has the
    benefit of marketing power primarily from hydroelectric plants, which
    do not have an associated fuel cost.\13

    A significant disadvantage of hydroelectric generation is the
    unpredictability of water availability.  BPA's historical sales
    figures demonstrate the dramatic effect that droughts can have on
    revenues.  For example, 1996 was the best water year since 1974, a
    fact which was crucial to BPA's attaining $96 million in net revenues
    for the year.  Due in part to the additional power generated, BPA's
    sales of surplus and nonfirm power increased 296 percent over the
    previous year.  As previously discussed, another significant
    disadvantage of BPA's hydropower generation is the cost associated
    with unique fish population improvement measures, which BPA estimated
    was $216 million in 1996.

    Another key advantage for BPA is that as a federal agency, it
    generally does not pay taxes.  In contrast, IOUs do pay taxes.
    According to the EIA, in 1995 IOUs paid taxes averaging about 14
    percent of operating revenues.  This average varies significantly
    from state to state due to differing state and local tax laws.  Taxes
    paid by IOUs include federal and state income taxes, real and
    personal property taxes, corporate franchise taxes, invested capital
    taxes, and municipal license taxes.  A specific example of a tax
    advantage BPA has relates to its nonfederal debt.  The interest
    income earned by holders of the bonds issued by the Washington Public
    Power Supply System is not subject to federal, personal, and some
    state income taxes.  This debt carries an interest rate that is lower
    than the interest rate applicable to debt of similar risk but without
    the tax-free provisions.  This provides a measure of benefit to BPA,
    which is contracted to pay the Supply System its debt service on the
    bonds.

    POGs, as publicly owned utilities, typically do not pay income taxes
    because they are units of state or local governments.  However, many
    POGs do make payments in lieu of taxes to local governments.  A
    study\14 of 670 public distribution utilities showed that the median
    net payments and contributions as a percentage of electric operating
    revenue were 5.8 percent.

    --------------------
    \11 We used the 1995 NERC configuration because the latest available
    data on average revenue per kWh by NERC region are from 1995.  NERC's
    configuration changed in 1996.  See appendix III for a further
    discussion.

    \12 Our analysis excluded IOU and POG nuclear plants that are
    mothballed and thus provide no capacity while resulting in
    significant capital costs.  Mothballed nuclear plants can be either
    incomplete plants that have had construction terminated or completed
    plants that have been shut down either temporarily or permanently.
    Under generally accepted accounting principles, these costs are
    either written off or, if deemed allowable by the applicable
    regulator, are classified as "regulatory assets" and included in
    rates through amortization.  Inclusion of these "regulatory assets"
    would have increased the POG and IOU investment.

    \13 Approximately 7 percent of the electricity marketed by BPA in
    fiscal year 1996 was produced from nuclear energy.

    \14 1994 Payments and Contributions by Public Power Distribution
    Systems to State and Local Government, American Public Power
    Association, March 1996.

             MANAGEMENT ACTIONS
    -------------------------------------------------- Appendix VIII:3.3.2

    BPA management has taken several actions that are intended to address
    the intense wholesale electricity competition in the Pacific
    Northwest.  These actions have helped make it possible for BPA to
    lower rates by about 13 percent for fiscal years 1997 through 2001.
    Management's actions have included setting cost reduction targets,
    reducing both agency and contractor staff, and refinancing nonfederal
    debt and Treasury bonds.

    Since 1994, BPA management has set cost reduction targets.  To meet
    those targets, BPA has analyzed its various spending plans--such as
    its fiscal year 1995 budget submission and expenses shown in rate
    proposals--and has reduced the expenses that were shown for future
    years in those plans.  The cumulative total, according to BPA's 1996
    annual report, is a cost reduction of $600 million per year.  BPA
    states that this reduces expenses that would otherwise have been
    incurred by $600 million per year during fiscal years 1997 through
    2001 and allowed for a 13-percent rate decrease for those years.  The
    cuts in planned expenses have been widespread to include BPA's
    marketing and production, conservation, transmission, and other
    activities.

    Staff reductions are also part of management's plan.  According to
    BPA, it has reduced its staff from a total of 3,755 full time
    equivalents (FTEs) in March 1994 to a total of 3,160 by the end of
    fiscal year 1996.  The agency plans a further reduction to 2,755 FTEs
    in fiscal year 1999.  In addition, BPA told us that it has reduced
    its contractor full time equivalents (CFTEs) from 1,911 in fiscal
    year 1994 to 1,077 at the end of fiscal year 1996.

    In addition, BPA has refinanced its nonfederal debt and Treasury
    bonds to keep its interest expense as low as possible.  BPA also
    plans to use revenue financing (funding capital acquisitions from
    current revenues) in some instances to reduce future financing costs.
    These plans and actions are consistent with those taken by IOUs in
    preparation for competition.

    BPA's management is also working with customers to come to an
    agreement on phasing out the residential exchange program.  This
    program allows certain utilities access to BPA's power on an
    "exchange" basis.  If the utilities' average power costs are higher
    than the cost of BPA power, the utilities are authorized to
    "exchange" a certain limited amount of their higher cost power with
    BPA.  BPA reimburses the utilities for the difference between the
    higher costs and BPA's cost.  The benefiting utilities are to assure
    that the exchanged power is sold only to residential and small farm
    customers.  This program cost BPA $196 million in fiscal year 1996.
    The elimination of the program is not, however, within BPA's
    discretion.  The program is mandated by the Northwest Power Act, and
    legislative action would be required to eliminate it.

             TRANSMISSION SYSTEM
    -------------------------------------------------- Appendix VIII:3.3.3

    BPA's extensive transmission system is a significant mitigating
    factor in assessing the risk of loss to the federal government.  BPA
    owns 75 percent of the total bulk power transmission line system in
    the region.  Ownership of such a large portion of the Pacific
    Northwest's transmission capacity should provide BPA with
    considerable ability to generate fees for access to this system when
    wholesale electricity competition is fully realized.  BPA has advised
    us that in the event that it is unable to sell its power at a level
    that recovers all costs, it might be able to use its massive
    transmission system to recover stranded costs.  This could involve
    allocating stranded generation costs, in whole or in part, to
    transmission charges for a period of years.

    One uncertainty regarding stranded cost recovery relates to FERC's
    requirement that utilities separate transmission and generating
    functions.  BPA has separated these functions administratively, but
    new legislation would be required to establish two separate legal
    entities--for instance, two government corporations.  The use of
    transmission revenues for stranded cost recovery could depend on the
    provisions of this legislation.

       RISK OF LOSS FROM TETON DAM
       PROJECT IS PROBABLE
    ------------------------------------------------------ Appendix VIII:4

    We identified one small project that serves BPA for which we believe
    financial loss to the federal government is probable.  This project,
    Teton Dam, was a multipurpose project on the Teton River in Idaho
    built by the Bureau of Reclamation.  The dam failed in 1976 when it
    was substantially complete, resulting in flooding, loss of life, and
    loss of the facilities.  Had the project been completed,
    power-related construction costs of about $7.3 million and irrigation
    costs of about $56.6 million would have been included in BPA's power
    rates for eventual repayment to Treasury.

    Since the failure of the project in 1976, these costs have been
    carried on the books of the Bureau of Reclamation as construction
    work-in-progress (CWIP).  While CWIP assets normally accrue interest
    charges, the Teton project has accrued no interest since 1976.  We
    estimate that since that time, interest charges of about $5 million,
    at the project interest rate of 3.25 percent, would normally have
    been paid to Treasury.

    The project's power-related construction costs are in the Federal
    Columbia River Power System's consolidated financial statements in
    the "Other Asset" category and are part of BPA's appropriated debt
    balance.  However, provisions for recovery of this amount have not
    been made.  BPA officials told us that since the project was not
    formally completed and placed in service, its costs cannot be put
    into BPA's rates.

    A Bureau of Reclamation official told us that it has no plans for
    further construction at the site and that the project should be
    written off.  According to this official, however, this would require
    deauthorization of the project by the Congress.  Regardless of
    whether the project is deauthorized, we believe these costs are
    unlikely to ever be recovered.

    RISK ASSESSMENT FOR THE TENNESSEE
    VALLEY AUTHORITY
    ========================================================== Appendix IX

    At September 30, 1996, the Tennessee Valley Authority (TVA) had $27.9
    billion of debt and $6.3 billion of deferred assets, which leaves TVA
    with far more financing and deferred assets than its potential
    competitors.  The risk that TVA will cause the federal government to
    incur losses is remote as long as TVA retains a position in its
    service area that is protected from competition--similar to a
    traditional regulated utility monopoly.\1

    However, if this position changes and TVA is required to compete at a
    time when wholesale prices are expected to be falling, its high fixed
    and deferred assets compared to neighboring utilities make it
    reasonably possible that the federal government would incur future
    losses.

    --------------------
    \1 Regulated monopolies are permitted by the government when
    unregulated market forces (for example, economies of scale) would
    naturally drive the market from competition to monopoly.  In such
    situations, the government designates a single seller of a
    well-defined product and regulates it to ensure delivery at
    acceptable prices.

       THE FEDERAL GOVERNMENT'S
       FINANCIAL INVOLVEMENT
    -------------------------------------------------------- Appendix IX:1

    The federal government has financial exposure because of its nearly
    $28 billion of direct and indirect financial involvement with TVA.
    As shown in table IX.1, the federal government's direct financial
    involvement, which consists of appropriated debt\2 and Federal
    Financing Bank (FFB) debt, was about $3.8 billion as of September 30,
    1996.  The federal government's indirect financial involvement, which
    consists of TVA's public debt, was $24.1 billion as of September 30,
    1996.

                                   Table IX.1

                       The Federal Government's Financial
                      Involvement in the Tennessee Valley
                       Authority as of September 30, 1996

                             (Dollars in billions)

                                              Financial involvement
                                        ----------------------------------
    Description                             Direct    Indirect       Total
    ----------------------------------  ----------  ----------  ==========
    Appropriated debt                         $0.6                    $0.6
    FFB debt                                   3.2                     3.2
    Public debt                                          $24.1        24.1
    ======================================================================
    Total                                     $3.8       $24.1       $27.9
    ----------------------------------------------------------------------
    Source:  TVA's fiscal year 1996 annual report.

    --------------------
    \2 In the case of appropriated debt, TVA is required to repay all but
    $258.3 million of the appropriations that were used for capital
    investments, plus interest.  TVA is not required to repay the entire
    appropriated debt balance because the federal government wanted to
    retain an equity interest in the assets of the corporation.  However,
    these reimbursable appropriations are not technically considered
    lending by the Treasury and are not included in TVA's debt cap.  TVA
    refers to this debt as "appropriation investment" and considers it to
    be equity.  Accordingly, TVA considers the annual payments a
    reduction of equity capital and the annual return a dividend.  For
    purposes of this report, we refer to the annual payments as debt
    (principal) payments and the annual return as interest expense.

          DIRECT FINANCIAL INVOLVEMENT
    ------------------------------------------------------ Appendix IX:1.1

    TVA's appropriated debt consists of appropriations that were
    primarily used to construct TVA's hydroelectric and fossil plants,
    transmission system, and other general assets of the power program.
    Substantially all of this debt was incurred from TVA's inception in
    1933 through 1959 when the TVA Act was amended to give TVA the
    authority to "self-finance." The 1959 amendments to the TVA Act
    require TVA to make annual principal payments (currently $20 million)
    to Treasury from net power proceeds plus a market rate of return\3

    (interest expense) on the balance of this debt.  The annual principal
    payments are to continue until the debt is paid down to $258.3
    million.  TVA estimates that it will pay down its appropriated debt
    balance to $258.3 million by the year 2014.  TVA is required to
    continue to pay annual interest on this balance but is not required
    to repay the remaining principal.

    TVA's FFB debt stems from authority granted to it in the 1959
    amendments to the TVA Act.  The amendments authorized TVA to issue
    bonds, notes, and other evidence of indebtedness to the public and
    the government up to a total of $750 million.  Since then, TVA's debt
    limit has been increased four times by the Congress:  to $1.75
    billion in 1966, $5 billion in 1970, $15 billion in 1975, and $30
    billion in 1979.  In 1994, TVA's Chairman announced that TVA would
    stop increasing its debt by October 1997.  If this plan is achieved,
    TVA would have an internal cap on its debt that is about $2 billion
    below its $30 billion statutory debt limit.  TVA's outstanding debt
    was incurred primarily to finance the construction of its nuclear
    program.

    For direct involvement, the federal government would incur a future
    loss if TVA failed to make payments on its outstanding appropriated
    and FFB debt.

    --------------------
    \3 The annual rate of return (interest expense) on TVA's appropriated
    debt is based on the computed average interest rate paid by Treasury
    on its total marketable public obligations as of the beginning of
    each year.  Total marketable obligations include all outstanding
    short-term and long-term marketable Treasury securities, including
    Treasury bills, notes, bonds, and FFB securities.

          INDIRECT FINANCIAL
          INVOLVEMENT
    ------------------------------------------------------ Appendix IX:1.2

    Like its FFB debt, TVA's authority to issue public debt stems from
    the authority granted under the 1959 amendments to the TVA Act.  This
    debt has been issued primarily to finance the construction of TVA's
    nuclear power program.  The federal government's involvement in this
    debt is indirect because, although the federal government does not
    explicitly guarantee this debt, the major credit rating agencies rate
    this debt as if it has an implicit federal guarantee.  Therefore,
    TVA's public debt is rated based primarily on TVA's links to the
    federal government rather than on the criteria that would be applied
    to a stand-alone corporation.  As a result, the private lending
    market has provided TVA with access to billions of dollars of
    financing at favorable rates.  Debt service on TVA's public debt,
    which is payable solely from TVA's net power proceeds, generally has
    precedence over the payment of TVA's appropriated debt.

    For indirect involvement, the federal government would incur future
    losses as a result of unreimbursed costs related to any actions it
    took to prevent default on the debt service requirements on TVA's
    outstanding public debt.

       RISK OF LOSS FROM TVA IS REMOTE
       UNDER CURRENT STRUCTURE
    -------------------------------------------------------- Appendix IX:2

    We believe there are two major factors that protect TVA from
    competition and result in TVA operating in a manner similar to a
    traditional regulated electric utility monopoly.  First, in nearly
    all instances, TVA's contracts with its 160 distributors
    automatically renew each year and require that at least a 10-year
    notice be given before the distributors can switch to another power
    company.  Second, TVA is exempt from the wheeling provisions of the
    Energy Policy Act of 1992.  This exemption generally prevents other
    utilities from using TVA's transmission system to sell power to
    customers inside TVA's service area.  TVA also has the added
    advantage of being able to set its own rates with a minimum of
    oversight.  These protections and advantages result in TVA's service
    area being substantially without wholesale competition.  We believe
    the risk of loss to the federal government is remote as long as TVA
    remains in this protected position.

          LONG-TERM CONTRACTS PROVIDE
          STABILITY AND ENSURED CASH
          FLOW
    ------------------------------------------------------ Appendix IX:2.1

    TVA's wholesale contracts with its 160 distributors, representing 83
    percent of TVA's load, are generally long-term, which assure it a
    relatively stable customer base and cash flow.  Except for Bristol,
    VA, the wholesale power contracts between TVA and its distributors
    contain a 20-year term that automatically renews each year (referred
    to as the "evergreen" provision) and require that the distributors
    give TVA at least a 10- to 15-year notice of cancellation.  This 10-
    to 15-year notice provision effectively locks the distributors into
    purchasing power from TVA since obtaining price quotes for power to
    be supplied beginning 10 to 15 years into the future is generally not
    feasible.  All of the power contracts between TVA and its
    distributors are "full requirements" contracts that require the
    distributors to purchase all of their electric power from TVA.

          TVA'S EXEMPTION FROM
          "WHEELING" PROVISIONS
          PROTECTS AGAINST OUTSIDE
          COMPETITION
    ------------------------------------------------------ Appendix IX:2.2

    TVA is further insulated from competition by a specific exemption
    from wheeling provisions of the Energy Policy Act of 1992.  Under the
    act's provisions, the Federal Energy Regulatory Commission (FERC) can
    generally compel a utility to transmit ("wheel") electricity
    generated by another utility into its service area for sale to
    wholesale customers.  The act acknowledges that with certain
    exceptions, TVA is legally prohibited from selling power outside its
    legislatively mandated service area (referred to as TVA's "fence")
    and therefore generally exempts it from having to transmit power from
    neighboring utilities to wholesale customers within TVA's service
    area.  Under the TVA Act and the Energy Policy Act of 1992, TVA is
    authorized to allow other utilities to use its transmission lines to
    wheel power through its service area to other utilities, but is not
    required to allow other utilities to sell power to customers within
    TVA's service area.

          TVA CAN SET RATES WITH
          MINIMUM OVERSIGHT
    ------------------------------------------------------ Appendix IX:2.3

    Another significant advantage for TVA is that unlike other utilities,
    the rates TVA charges for its electric power are not subject to
    review and approval by state public utility commissions or FERC.  TVA
    can, and in fact must under the TVA Act, set its rates to recover all
    power-related costs.  Because the long-term "evergreen" contracts and
    the exemption from the wheeling requirements allow TVA to operate
    like a traditional regulated monopoly, TVA can set rates at whatever
    level it deems necessary to recover all costs and, to a certain
    extent, not face the same competitive pressures as other utilities.
    Despite this advantage, as is discussed in the next section, TVA has
    chosen to defer a substantial amount of costs to future years rather
    than beginning to recover these costs from ratepayers.

       RISK OF LOSS IS REASONABLY
       POSSIBLE ABSENT PROTECTION FROM
       COMPETITION
    -------------------------------------------------------- Appendix IX:3

    Based on discussions with industry experts and TVA officials, it
    appears unlikely that TVA will be allowed to maintain its current
    regulated monopoly-type structure indefinitely and, at some future
    point, will have to compete with other utilities.  In a competitive
    environment, utilities that have low costs and the flexibility to
    adjust their rates to meet those being offered by other utilities are
    expected to be the most competitive.  We believe TVA's substantial
    fixed costs and deferred assets will limit TVA's flexibility to
    continue to offer competitive rates and could impact its ability to
    recover all costs in a future competitive environment when wholesale
    prices are expected to be falling.  Therefore, despite a number of
    mitigating factors, without protection from competition, we believe
    that it is reasonably possible under this scenario that the federal
    government would incur future losses as a result of its financial
    involvement with TVA.

          HIGH FIXED AND DEFERRED
          ASSETS WOULD IMPEDE TVA'S
          ABILITY TO COMPETE
    ------------------------------------------------------ Appendix IX:3.1

    TVA has chosen to defer costs related to its substantial nuclear
    investment to future years rather than currently including them among
    the costs being recovered from ratepayers and using the cash
    generated to pay down its debt.  As a result, TVA had accumulated $28
    billion of debt as of September 30, 1996, which resulted in over $2
    billion of interest expense in fiscal year 1996.

    The recovery of these deferred assets is being put off to the future
    and will most likely be scheduled to be recovered from ratepayers at
    a time when wholesale power rates are expected to be falling.  By
    choosing to keep its rates stable over the last 10 years, TVA's
    resulting high fixed and deferred assets will leave it vulnerable to
    future competition, similar to the Bonneville Power Administration's
    (BPA) situation.  As mentioned in appendix VIII, BPA's high fixed
    costs limited its flexibility to meet competitive challenges when
    electricity prices fell sharply in the Pacific Northwest in the last
    several years.  Like BPA, we believe that TVA's high fixed and
    deferred assets would limit its flexibility to react to falling
    wholesale prices that are likely to result from competition.
    However, unlike TVA, BPA has no deferred nuclear assets.

    Following is an assessment of several key ratios that demonstrate why
    we believe TVA's high fixed and deferred assets would make it
    vulnerable in a competitive environment.

          FLEXIBILITY RATIOS
    ------------------------------------------------------ Appendix IX:3.2

    To assess TVA's financial condition relative to its likely
    competitors, we compared certain flexibility ratios for TVA and 11
    neighboring investor-owned utilities (IOUs).\4 First, we computed the
    financing costs to revenue ratio, which indicates the percentage of
    operating revenues needed to cover the financing costs of the entity.
    The financing costs for TVA consist of the interest expense on its
    outstanding debt.  Due to the difference in the capital structure
    between TVA and the IOUs, we included preferred and common stock
    dividends in the financing costs for the IOUs because part of the
    IOUs' capital is derived from preferred and common stock and
    dividends represent the cost of this equity capital.  TVA's capital,
    on the other hand, is derived primarily from debt.  Next, we computed
    the fixed financing costs to revenue ratio, which indicates the
    percentage of operating revenues needed to cover the fixed portion of
    the financing costs.  For this ratio, we excluded the common stock
    dividend paid by IOUs because these are not contractual obligations
    that have to be paid.  For both of these ratios, the lower the
    percentage, the greater the financial flexibility of the entity.\5
    Table IX.2 shows the results of this comparison.

                                   Table IX.2

                     Comparison of Financial Ratios for TVA
                       and Neighboring IOUs That Indicate
                         Flexibility, Fiscal Year 1996

                                                                     Fixed
                                                 Financing       financing
                                                  costs to        costs to
                                                   revenue         revenue
    Utility                                      (percent)       (percent)
    --------------------------------------  --------------  --------------
    TVA                                               35.3            35.3
    American Electric Power                           14.9             7.2
    Carolina Power & Light                            15.4             6.5
    Cinergy                                           16.3             7.8
    Dominion Resources                                18.4             8.9
    Duke Power                                        13.4             4.5
    Entergy                                           16.7            11.0
    Illinova                                          13.8             8.8
    KU Energy                                         15.0             5.9
    LG&E Energy                                        3.6             1.5
    SCANA                                             18.6             8.4
    Southern                                          15.7             7.6

    IOU Summary
    ----------------------------------------------------------------------
    ======================================================================
    Average                                           14.7             7.1
    ======================================================================
    High                                              18.6            11.0
    ======================================================================
    Low                                                3.6             1.5
    ----------------------------------------------------------------------
    Source:  GAO analysis of 1996 annual reports.

    As indicated by table IX.2, TVA's ratio of financing costs to revenue
    is more than twice as high as the average financing costs for
    neighboring utilities.  TVA's ratio of fixed financing costs to
    revenue is almost five times higher than the average of its
    neighboring IOUs.  All of TVA's financing costs are interest expense
    and thus are fixed in the short term.  On the other hand, IOUs'
    common stock dividends are not contractual obligations that have to
    be paid.  We recognize that short-term stock prices would be
    negatively impacted by an IOU's decision not to pay dividends.
    However, IOUs have this flexibility and some have elected this option
    in the past.  These two ratios clearly show that because of high
    financing costs, TVA does not have the same level of flexibility as
    neighboring IOUs to lower prices to meet price competition.

    In addition to TVA's already relatively high financing costs, it also
    is exposed to substantial risk of rising interest rates.  In fiscal
    year 1996, TVA's interest payments alone amounted to just over $2
    billion, which represented about 35 percent of its fiscal year 1996
    operating revenue.  As TVA's approximately $28 billion in debt
    matures, the portion that is not repaid will likely need to be
    refinanced, thus exposing TVA to the risk of rising interest rates
    and even higher financing costs.  However, if rates decline, TVA will
    experience a decrease in financing costs.  For example, as of
    September 30, 1996, TVA had approximately $8 billion in long-term
    debt that will mature and need to be refinanced over the next 5
    years.  By the end of this 5-year period, for every 1 percentage
    point change in TVA's borrowing cost, its annual interest expense
    will increase or decrease by $80 million per year.  In addition, as
    of September 30, 1996, TVA had about $2 billion of short-term debt
    that would also be subject to changes in interest rates.

    --------------------
    \4 According to industry experts, TVA's competition would most likely
    come from nearby utilities because of the cost of wheeling power.  We
    recognize that utilities that do not border on TVA's service area,
    power marketers, and independent power producers (IPPs) also provide
    likely competition for TVA.  However, we believe that comparing TVA
    to its neighboring IOUs provides a reasonable basis for assessing
    TVA's ability to compete.  See appendix II for a description of these
    utilities.

    \5 See appendix II for a description and methodology for calculating
    these ratios.

          DEFERRED ASSET RATIOS
    ------------------------------------------------------ Appendix IX:3.3

    In addition to the two flexibility ratios above, we computed the
    ratios shown in table IX.3 to compare the magnitude of TVA's deferral
    of costs compared to its most likely competitors.  These ratios
    measure the relative amount of capital costs that will need to be
    recovered in the future via depreciation or amortization.  We
    computed the accumulated depreciation and amortization to gross
    property, plant, and equipment (PP&E) ratio to show how much PP&E has
    been depreciated and recovered through rates at September 30, 1996.
    A higher ratio indicates that more capital costs have been recovered
    through rates.  We also computed the deferred assets to gross PP&E
    ratio to show how much of total PP&E has not yet begun to be
    depreciated and taken into rates.  In this case, a lower ratio
    indicates fewer deferred assets and a better competitive position.

                                   Table IX.3

                     Comparison of Financial Ratios for TVA
                       and Neighboring IOUs That Indicate
                       Deferred Assets, Fiscal Year 1996

                                                 Accumulated
                                               depreciation/      Deferred
                                                amortization     assets to
                                               to gross PP&E    gross PP&E
    Utility                                        (percent)     (percent)
    ----------------------------------------  --------------  ------------
    TVA                                                 18.2          19.5
    American Electric Power                             39.8           1.9
    Carolina Power & Light                              37.2           1.9
    Cinergy                                             36.4           1.8
    Dominion Resources                                  37.5           1.1
    Duke Power                                          37.3           2.5
    Entergy                                             35.4           1.6
    Illinova                                            34.7           6.2
    KU Energy                                           42.0           2.5
    LG&E Energy                                         37.2           1.5
    SCANA                                               30.1           4.3
    Southern                                            31.9           2.0

    IOU Summary
    ----------------------------------------------------------------------
    ======================================================================
    Average                                             36.3           2.5
    ======================================================================
    High                                                42.0           6.2
    ======================================================================
    Low                                                 30.1           1.1
    ----------------------------------------------------------------------
    Note:  See appendix II for a description of the methodology used to
    calculate these ratios.

    Source:  GAO analysis of 1996 annual reports.

    TVA's ratio of accumulated depreciation and amortization to gross
    PP&E was 18 percent as of September 30, 1996, whereas similar ratios
    for the IOUs in the comparison group averaged 36 percent.  This ratio
    shows that only half as much of TVA's capital costs, in percentage
    terms, have been taken into its rate base via depreciation and
    amortization compared to the average for IOUs.

    The second ratio shows that TVA's deferred assets represent 20
    percent of its gross PP&E, while the ratio for the 11 IOUs averaged
    just 3 percent.\6 TVA's decision to not begin recovering the costs of
    the deferred nuclear plants when construction was stopped has
    increased the costs that must be recouped in the future.  These
    ratios show that while TVA has deferred substantial costs, its
    potential competitors have written down the assets they deem to be
    uneconomical at a much faster rate, which results in these utilities
    recovering costs at a much greater pace than TVA and thus having
    greater financial flexibility in the future.

    The primary component of TVA's deferred assets is $6.3 billion in
    capital costs for its nonproducing nuclear assets (Watts Bar 2 and
    Bellefonte 1 and 2 nuclear units\7 ).  TVA has deferred these costs
    based on its unique interpretation and application of accounting
    principles.  Despite the fact that there are no other deferred
    nuclear plants in the United States, TVA is treating Watts Bar 2 and
    the Bellefonte units similar to construction work-in-progress (CWIP).
    As such, the recovery of the costs of these assets will not begin
    until the units are either completed and placed in service or
    canceled.

    In December 1994, TVA determined it would not, by itself, complete
    Bellefonte units 1 and 2 or Watts Bar 2 as nuclear units.  However,
    TVA is still studying the potential for converting Bellefonte to a
    combined cycle plant and/or joint-venturing with a partner for
    completion of the plant.  This study is scheduled to be completed by
    the fall of 1997.  TVA also concluded, as part of its Integrated
    Resource Plan, that Watts Bar 2 should remain in deferred status
    until completion of the Bellefonte study.

    We believe that the $6.3 billion of costs are appropriately
    capitalized as an asset in accordance with Statement of Financial
    Accounting Standards (SFAS) No.  71, Accounting for the Effects of
    Certain Types of Regulation.  However, as we reported in 1995 (See
    our report Tennessee Valley Authority:  Financial Problems Raise
    Questions About Long-term Viability (GAO/AIMD/RCED-95-134, August 17,
    1995)), we believe that it is unlikely that these projects, which
    have not had any construction work done for 9 years, will ever be
    completed as nuclear units.  SFAS No.  90, Regulated
    Enterprises--Accounting for Abandonments and Disallowances of Plant
    Costs requires that "When it becomes probable that an operating asset
    or an asset under construction will be abandoned, the cost of that
    asset shall be removed from construction work-in-process." In our
    judgment, SFAS No.  90 requires that TVA's $6.3 billion of costs be
    reclassified from CWIP to "regulatory assets" and that amortization
    begin immediately.  We believe that TVA's continued exclusion of
    these costs from charges to ratepayers reduces the likelihood of
    recovery from ratepayers and puts the federal government at increased
    risk of absorbing these costs in the future.

    TVA charges the costs of its PP&E and canceled plants to ratepayers
    through depreciation and amortization expenses.  TVA is required by
    law to set rates so that power revenues cover all operating expenses,
    including depreciation and amortization.  While the nonproducing
    nuclear assets are not presently being depreciated or amortized, the
    annual interest expense from the debt associated with these assets is
    included in TVA's current charges to ratepayers.  By not recovering
    the costs of its deferred nuclear units from ratepayers and using the
    cash to pay off debt in prior years, TVA has developed high fixed
    costs and deferred assets which will place upward pressure on TVA's
    rates at a time when power rates are expected to be falling.

    --------------------
    \6 The IOUs deferred assets primarily represents construction
    work-in-progress.

    \7 TVA suspended construction activities on Watts Bar 2 in 1988, and
    the unit is currently in lay-up status.  In 1988 and 1985, TVA
    deferred construction activities at Bellefonte 1 and 2, respectively.

          INVESTMENT IN PP&E PER
          MEGAWATT OF GENERATING
          CAPACITY
    ------------------------------------------------------ Appendix IX:3.4

    Finally, to analyze TVA's competitiveness with its 11 neighboring
    utilities, we compared the investment in PP&E per megawatt of
    generating capacity--which depicts the relative cost of building
    generating plants--with the average system retail rates.  High
    investment in PP&E generally means higher rates.  As shown in figure
    IX.1, TVA has more invested in power plants in relation to their
    generating capacity than most other utilities in our comparison
    group, yet its rates are generally lower than the group.\8

       Figure IX.1:  Comparison of
       Investment in PP&E and Retail
       Rates Among TVA and Neighboring
       IOUs

       (See figure in printed
       edition.)

    Note:  Data for TVA are from fiscal year 1996.  TVA's average system
    retail rate represents the average system retail rates for its
    distributors.

    Source:  GAO analysis of financial data in 1995 annual reports and
    Financial Statistics of Major U.S.  Investor-Owned Utilities 1995 and
    Inventory of Power Plants in the United States, Energy Information
    Administration (EIA), January 1996.

    TVA's relatively high investment in utility plant results from its
    high investment in nuclear plants.  As shown in figure IX.1, of the
    11 utilities in our comparison group, only Illinova has invested more
    in PP&E per megawatt of generating capacity than TVA.  Figure IX.1
    also shows that Illinova's average rate is higher than the average
    system rates for TVA's distributors.  In addition, KU Energy, which
    had the lowest investment in PP&E per megawatt of generating
    capacity, also had the lowest average rates.  TVA's relationship
    between its investment in PP&E per megawatt of generating capacity
    and rates does not follow this pattern.  TVA has invested more in
    assets per megawatt of generating capacity than all but one IOU in
    our comparison group, but has lower rates than all but three of the
    IOUs.  TVA's low rates have been significantly impacted by its
    decision to defer substantial costs and cost advantages--discussed
    later in this appendix--from being a government corporation.

    --------------------
    \8 Our analysis excluded nuclear plants that are mothballed and thus
    provide no capacity while resulting in significant capital costs.
    Mothballed nuclear plants can be either incomplete or completed
    plants that have had construction terminated or have been shut down
    either temporarily or permanently.  Under generally accepted
    accounting principles, these costs are either written off or, if
    deemed allowable by the applicable regulator, are classified as
    "regulatory assets" and included in rates through amortization.
    Inclusion of these "regulatory assets" would have increased the IOUs'
    investment.

          TVA FACES SOME COMPETITIVE
          PRESSURE TODAY
    ------------------------------------------------------ Appendix IX:3.5

    While TVA's wholesale rates look relatively competitive in the
    Southeast, we believe TVA's competitive position will be weakened
    when it begins to recover the $6.3 billion of deferred assets.  TVA's
    vulnerability to wholesale competition, without protection, was
    recently demonstrated when one of its customers, Bristol Virginia
    Utilities Board, announced that it will leave the TVA system for
    Cinergy, Inc.  Cinergy offered Bristol firm wholesale power at 2.59
    cents per kilowatthour (kWh) for 7 years--40 percent lower than TVA's
    comparable wholesale rate of 4.3 cents per kWh.  According to its
    General Manager, Bristol will save $70 million over 7 years, and the
    typical residential customer will save $11 per month.  Bristol, which
    is on the border of TVA's service area, was able to purchase this
    power because it had given TVA written notice of its intent to cancel
    its power contract and had received a unique exemption in the Energy
    Policy Act of 1992, which allows other utilities to transmit (wheel)
    electricity to Bristol over TVA's power lines.  As a result of
    Bristol's exemption, TVA is required to wheel Cinergy's power to
    Bristol.  While we recognize that Cinergy may have offered this power
    to Bristol at marginal rates, this is the type of competitive
    situation that TVA might face regularly if it lost its current
    protections from competition.

    The concerns of TVA industrial customers--which represent
    approximately 15 percent of its load--about future price increases
    will put pressure on TVA not to raise rates and thus to continue to
    defer costs and maintain high debt levels.  Unlike residential
    customers, the larger industrial entities are willing and able to
    leave a utility's service area to find alternative, cheaper sources
    of power.  Officials from the Tennessee Valley Industrial Committee
    and Associated Valley Industries, which represent industries that
    purchase electric power directly from TVA or through TVA's rural or
    public power distributors, told us that they believe there is room
    for TVA to lower its firm power rates.  They stated that any increase
    in industrial rates would be unwelcome because they believe TVA's
    current rates are too high when compared to the firm industrial rates
    of other utilities.  The officials said they would continue to
    advocate cost control and more favorable firm power rates.

          OTHER FACTORS COULD
          NEGATIVELY AFFECT TVA
    ------------------------------------------------------ Appendix IX:3.6

    In addition to TVA's high fixed and deferred assets, we believe the
    concentration of TVA's sales to its five largest distributors and the
    number of TVA's customers that are already connected to the
    transmission line of other utilities also contribute to TVA being
    vulnerable to future competition.

    TVA's customer profile may increase competitive pressures.  TVA sells
    electric power at wholesale rates to 160 municipal and cooperative
    power distributors, the majority of which are relatively small.  In
    fiscal year 1996, over 63 percent of the distributors had a peak
    demand of less than 110 megawatts.  However, five municipal
    distributors account for over 34 percent of TVA's total sales to
    distributors (Chattanooga, Knoxville, Memphis, and Nashville,
    Tennessee, and Huntsville, Alabama).  TVA's largest distributor, the
    City of Memphis, had a peak demand of about 2,943 megawatts in fiscal
    year 1996--representing approximately 11 percent of TVA's total sales
    to distributors.  Because Memphis is at the edge of TVA's service
    area, it may be particularly vulnerable to competitive advances of
    other utilities.

    Officials from these large distributors expressed concern that TVA's
    power contracts offer distributors no flexibility to purchase power
    from outside sources.  The officials discussed a number of possible
    options that TVA should consider, including shortening the length of
    its power contracts, giving distributors the freedom to fill some of
    their requirements from outside sources, or tying its wholesale rates
    to a market index.  The large distributors hope to use their leverage
    in order to compel TVA to renegotiate their power contracts.  In a
    competitive environment, TVA would likely have to lower the rates of
    these distributors or run the risk of losing them as customers, which
    could be financially crippling to TVA.

    Another competitive pressure arises because although TVA is exempt
    from the wheeling provisions of the Energy Policy Act of 1992, 12 of
    TVA's 160 distributors are already interconnected with other
    utilities.  Therefore, even if other utilities are prevented from
    using TVA's lines, these distributors could get power from other
    sources after their contracts with TVA expire.  These distributors
    are scattered around the periphery of TVA's service territory.  Some
    of these distributors are connected to both TVA and other utilities,
    whereas others are not connected to TVA's transmission network at
    all.  According to one TVA study,\9 26 percent of the load for
    distributors on the periphery of TVA's system is served by
    transmission lines owned by other utilities.  This load accounts for
    approximately 2 percent of TVA's total load.  As competition
    intensifies in the region, TVA could lose distributors to other
    suppliers using existing and future transmission connections.

    --------------------
    \9 The Ties That Bind:  TVA in a Competitive Electric Market, Palmer
    Bellevue, a division of Coopers & Lybrand L.L.P., April 1995.

          MITIGATING FACTORS REDUCE
          RISK OF LOSS
    ------------------------------------------------------ Appendix IX:3.7

    TVA has a number of factors that mitigate its high fixed and deferred
    assets.  These factors include inherent cost advantages, management
    actions to cut operating expenses, and an extensive transmission
    system.  Because of these factors, we believe the risk of loss to the
    federal government is reduced but is still reasonably possible.

             INHERENT COST ADVANTAGES
    ---------------------------------------------------- Appendix IX:3.7.1

    According to bond rating agencies, TVA's creditworthiness is based on
    its links to the federal government rather than on the criteria
    applied to a stand-alone corporation.  As a result, the private
    lending market has provided TVA with access to billions of dollars of
    financing at favorable rates.  In accordance with section 15d of the
    TVA Act, TVA's debt issuances explicitly state on the bond prospectus
    that the bonds are neither legal obligations of, nor guaranteed by,
    the U.S.  government.  Nevertheless, TVA's bonds are rated by the
    major bond rating agencies as if they have an implicit federal
    guarantee.  One of the major bond rating services believes, and we
    concur, that without the links to the federal government, TVA would
    have a lower bond rating and higher cost of funds.

    TVA also enjoys many advantages as the direct result of being a
    federal corporation.  As a federal government corporation, TVA is
    exempt from federal and state income taxes and does not pay various
    local taxes.  Therefore, TVA, as a nonprofit entity, does not have to
    generate the net income that would be needed by an IOU to provide an
    expected rate of return.  However, the TVA Act requires TVA to make
    payments in lieu of taxes to state and local governments where power
    operations are conducted.  The base amount TVA is required to pay is
    5 percent of gross revenues from the sale of power to other than
    federal agencies during the preceding year--these amounted to about
    $256 million in fiscal year 1996.  In addition, according to TVA, its
    distributors are required to pay various state and local taxes which
    amounted to about $125 million, or about 2 percent of the total
    fiscal year 1995 operating revenues of TVA and the distributors.  In
    comparison, according to the EIA, IOUs pay about 14 percent of
    operating revenues for taxes.  In addition, interest income for TVA's
    bondholders is generally exempt from state income taxes, which
    further lowers TVA's costs of funds.

    TVA has relatively more hydroelectric power than neighboring
    utilities.  Eleven percent of its power comes from hydroelectric dams
    built between 1912 (pre-TVA) and 1972--20 to 85 years ago, whereas,
    on the average, only about 6 percent of the power from other
    utilities comes from hydroelectric dams.  These established
    hydroelectric projects are relatively inexpensive and have no
    associated fuel costs.  TVA continues to upgrade and improve its
    hydroelectric plants.  TVA has 113 hydro units at 29 conventional
    dams and the Raccoon Mountain Pumped-Storage facility on the
    Tennessee River and its tributaries that produce electricity.  TVA is
    refurbishing and upgrading 88 hydro units at 24 hydroelectric dams as
    part of its Hydro Modernization Program.  In addition, TVA also
    dispatches power from four hydroelectric dams that are owned by a
    subsidiary of the Aluminum Company of America.  Table IX.4 shows the
    contrast between TVA and other utilities in the percentage of power
    from different generating sources.

                                   Table IX.4

                      Percentage of Power Generation From
                      Different Sources for TVA and Other
                                Utilities, 1996

    Utility                          Coal  Nuclear     Gas   Hydro   Other
    -----------------------------  ------  -------  ------  ------  ------
    TVA                              65.0     24.0       0    11.0       0
    Other utilities                  57.5     24.2     9.7     6.1     2.5
    ----------------------------------------------------------------------
    Source:  TVA and EIA.

    TVA also has a competitive advantage because it purchases low cost
    hydroelectric power from Southeastern.  According to TVA, it
    satisfies about 2 percent of its annual power needs from the power
    marketed by Southeastern, which represents about 80 percent of the
    power marketed by Southeastern from the dams on the Cumberland river.
    In fiscal year 1996, TVA purchased this power at 0.8 cents per
    kWh.\10

    --------------------
    \10 See volume I for a discussion of Southeastern's cost advantages
    that allow it to market low cost power.

             MANAGEMENT ACTIONS AND
             PLANS TO REDUCE COSTS AND
             INCREASE REVENUES
    ---------------------------------------------------- Appendix IX:3.7.2

    Recently, TVA has taken a number of steps to reduce its operating and
    capital expenses and become more competitive.  For example, it
    canceled a number of its nuclear construction projects in the early
    1980s and reduced annual operating costs by nearly $800 million,
    primarily by cutting its workforce in half (from 34,000 in 1988 to
    16,000 in 1996) and refinancing its debt at lower interest rates.
    Another important step for TVA is the completion of its Watts Bar 1
    and restarting of its Browns Ferry 3 nuclear power units, which were
    major reasons for TVA's increased debt in recent years.  In addition,
    according to TVA, it has internally capped its debt limit at about
    $28 billion and plans to finance its future capital expenditures from
    operations.

    On July 22, 1997, TVA released a 10-year business plan that
    identifies actions it plans to take to position its power operations
    to meet the challenges from the coming restructured marketplace.
    This plan calls for TVA to (1) increase power rates enough to
    increase annual revenues by about 5.5 percent ($325 million), (2)
    take various actions to reduce its total cost of power by about 16
    percent by fiscal year 2007, (3) limit annual capital expenditures to
    $595 million, and (4) reduce debt by about 50 percent from $27.9
    billion as of September 30, 1996, to $13.8 billion by fiscal year
    2007.  To the extent TVA is able to use the cash generated from
    increasing rates, reducing expenses, and capping future capital
    expenditures to pay down debt, the risk of loss to the federal
    government is reduced.  In addition to these actions, the plan calls
    for TVA to change the length of the wholesale power contracts with
    its distributors from a rolling 10-year term to a rolling 5-year term
    beginning 5 years after the amendment.  However, reducing the length
    of the wholesale contracts with its distributors could increase the
    risk of loss to the federal government.

             EXTENSIVE TRANSMISSION
             SYSTEM
    ---------------------------------------------------- Appendix IX:3.7.3

    A major advantage to TVA in a competitive environment will be that
    TVA owns and operates an extensive transmission system extending into
    seven states and consisting of 17,000 miles of high voltage lines
    interconnecting with 16 neighboring utilities at 57 interconnecting
    points.  Even if TVA is forced to allow other utilities to use its
    power lines to sell power to its customers, TVA will have the right
    to charge the other utilities a fee for using its transmission lines.
    During 1996, TVA spent $228 million to expand and improve the
    reliability of the transmission system, and it projects spending an
    average of approximately $183 million annually for fiscal years 1997
    through 2001 to further improve and upgrade its transmission
    facilities.

    TVA believes it has legal authority to recover stranded costs from
    customers that may choose to leave the system and will be able to use
    charges for use of its transmission lines to do so.  Various other
    mechanisms could also be used for the recovery of stranded costs,
    including fees charged to customers that have or may decide to
    discontinue purchasing TVA power.  However, TVA recognizes that there
    are legal, political, and commercial uncertainties regarding the
    possibility of recovering stranded costs.

    (See figure in printed edition.)Appendix X
    COMMENTS FROM THE RURAL UTILITIES
    SERVICE
    ========================================================== Appendix IX

    (See figure in printed edition.)

    (See figure in printed edition.)

    The following are GAO's comments on the Department of Agriculture's
    letter dated July 8, 1997.

    GAO COMMENTS

    1.  Our April 1997 report presented information on the financial
    condition of the RUS loan portfolio as of September 30, 1996, and
    included selected financial statistics and ratios reported by the RUS
    borrowers.  We also noted in that report that "RUS' electricity
    portfolio faces the possibility of additional financial stress due to
    increasing competition among the providers of electricity." The
    current report addresses this issue and assesses the likelihood of
    future losses to the federal government from its direct and indirect
    involvement in RUS.  For example, we determined that $10.5 billion of
    the $32.3 billion, or 33 percent, of the total electricity portfolio
    represented loans to borrowers that are in bankruptcy or otherwise
    financially stressed.  It is probable that the federal government
    will continue to incur substantial losses from loan write-offs
    relating to RUS borrowers that are currently bankrupt or financially
    stressed.

    It is also probable that future losses will arise from other RUS
    borrowers with high production costs based on our analysis that shows
    that 27 of the 33 viable G&T borrowers had higher production costs
    than the IOUs in their regions.  We believe that current production
    costs will be a key factor in the ability of RUS G&Ts to compete in a
    deregulated environment.  In fact, RUS officials told us that several
    borrowers currently considered viable by RUS have already asked RUS
    to renegotiate or write off their debt because they do not expect to
    be competitive due to high production costs.

    2.  We agree that the publicly rated G&Ts are better positioned to
    remain viable power supply borrowers.  However, only 7 of the 55 RUS
    power supply borrowers are publicly rated by bond agencies.  In
    addition, in May 1995, Moody's Investors Service issued an opinion on
    the viability of RUS borrowers in their report entitled, Moody's
    Outlines Risk Profile for Electric Cooperatives.  It states:

         "Historically, G&Ts have had a number of structural
         disadvantages in competing with IOUs, including generally higher
         rates, transmission constraints, lower equity ratios, and
         capacity planning problems.  Moreover, they also face the need
         to find new sources of funding to compensate for the reduced
         availability of guaranteed loans from RUS.  We expect that the
         confluence of factors will result in the deterioration of the
         overall credit quality of the cooperative industry over the next
         5 to 10 years."

    3.  Discussed in the "Agency Comments and Our Evalution" section of
    the letter in volume 1.

    (See figure in printed edition.)Appendix XI
    COMMENTS FROM SOUTHEASTERN,
    SOUTHWESTERN, AND WESTERN
    ========================================================== Appendix IX

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    The following are GAO's comments on the three PMAs' letter dated July
    1, 1997.

    GAO COMMENTS

    1.  Discussed in the "Agency Comments and Our Evaluation" section in
    the letter in volume 1.

    2.  We agree.  We have added to volume 1 of our report a discussion
    of the 1983 change in guidance on setting interest rates for
    PMA-appropriated debt.

    3.  We have appropriately included all salient points relative to the
    three PMAs' net cost and risk to the federal government in both
    volume 1 and appendix VII of volume 2.  Additionally, we disagree
    with the three PMAs' characterization of certain costs as
    "disadvantages." For example, we do not agree that including future
    replacement costs in Southwestern's power rates have increased its
    rates by 10 to 15 percent.  The revenues generated by including these
    costs in current rates have actually been applied to current year
    appropriations or other appropriated debt.  As a result, Southwestern
    has been able to repay most of its recent higher interest rate debt.
    Thus, its weighted average interest rate was 2.9 percent,
    considerably lower than Southeastern's (4.4 percent) and Western's
    (6.0 percent).  Southwestern's repayment of higher rate debt has
    enabled it to minimize interest expense and electricity rates for its
    customers.  Rather than viewing this as a "cost disadvantage" to
    Southwestern or its customers, we believe Southwestern has managed
    its appropriated debt using sound business principles and has
    minimized the interest expense that must be recovered through rates.

    Regarding the requirement to repay irrigation debt, the three PMAs
    overstate the impact of this requirement on Western.  Our review of
    Western's fiscal year 1996 financial statements shows that, as of
    September 30, 1996, the cumulative total amount of irrigation
    investment repaid by Western was just over $33 million.  A cumulative
    total repayment of that amount does not represent a significant cost
    disadvantage for an entity that has had gross annual operating
    revenues averaging more than $775 million over the 5-year period from
    1992 through 1996.  We agree that to the extent that power revenues
    are actually used to repay irrigation investment it is a disadvantage
    to power customers; however, we do not agree that the impact has been
    significant enough to be highlighted in volume 1 of the report.

    The three PMAs also overstate the likely impact of Western's
    potential repayment of future irrigation investments.  The billions
    of dollars that the three PMAs refer to are not costs that have been
    incurred, and it is questionable whether they will ever be incurred.
    To the extent that these planned future costs are included in
    Western's current rates, any resulting revenue would actually be
    applied to other appropriated debt.  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 or
    its customers.

    Regarding payments made in lieu of taxes, we acknowledge in appendix
    VII that the Boulder Canyon Project, marketed by Western, makes
    annual payments in lieu of taxes to the states of Arizona and Nevada.
    In 1995, the payments totaled about $600,000, or 1.2 percent of the
    Boulder Canyon Project's operating revenue.  In contrast, according
    to the Energy Information Administration, IOUs paid taxes averaging
    about 14 percent of operating revenues in 1995.  Moreover, despite
    raising the issue of payments in lieu of taxes, the three PMAs have
    been unable to substantiate that they or the operating agencies have
    made any payments in lieu of taxes other than those to the states of
    Arizona and Nevada.

    4.  We concur with the three PMAs' comment that the three PMAs'
    costs, and resultant power rates, are generally lower than their
    competitors.  In our report, we used average revenue per kilowatthour
    (kWh) to demonstrate this favorable comparison.

    5.  We disagree.  It is appropriate to include the irrigation debt in
    our discussion of the federal government's financial involvement in
    electricity-related activities because it is to be recovered
    primarily by power revenues.

    6.  We do not agree that the investments in Russell, Truman, and
    Washoe are "new investments." Construction on Russell began in 1976,
    the four operating units came on line in 1986, and the four
    nonoperational units were completed in 1992.  The nonoperational
    units at Truman were specifically deferred from inclusion in rates as
    part of FERC's approval of Southwestern's 1989 power rates.  Power
    sales at Washoe began in 1988.  Thus, Russell, Truman, and Washoe
    have a history of operating and financial problems.  We see no
    evidence provided by the three PMAs that this troubled past will not
    continue.  We concur that Mead-Phoenix, which began operation in
    April 1996, can be considered a "new investment." However, the
    results we report for Mead-Phoenix's first 9 months of operation,
    coupled with the lack of customers for Western's share of capacity,
    demonstrate that this investment meets the criteria for a probable
    future loss to the federal government.

    7.  In volume 1, we conclude that the three PMAs are competitively
    sound overall, except for a few projects or rate-setting systems
    that, taken as a whole, make risk of some loss to the federal
    government probable.  We then discuss these projects in detail in
    appendix VII.  Because we assess the three PMAs as competitively
    sound overall, a discussion of mitigating factors in volume 1 is not
    needed.  The mitigating factors we identified for each of the three
    PMAs are discussed in appendix VII.

    8.  We agree that the risk of loss at Russell is conditional.  As
    stated in appendix VII, if the nonoperational pumping units do not
    operate commercially, it is probable that the federal government will
    lose its entire $518 million investment.  In addition, we state that,
    if full deployment of the pumping units continues to be delayed, the
    risk of loss to the federal government is reasonably possible.  Also,
    if the nonoperational pumping units are allowed to operate
    commercially and placed into rates in the near future, the
    Georgia-Alabama-South Carolina system, of which Russell is a part,
    should be able to remain competitive.  Under this scenario, the risk
    of loss to the federal government is remote.  We have added language
    to appendix VII to clarify the conditional assessment of risk at
    Russell.

    9.  The statement that the "Army Corps of Engineers expect this
    project's pumpback units to operate" is contrary to what the Corps of
    Engineers told us.  In addition, the fact that the costs associated
    with the nonoperational pumping units have been deferred from
    Southwestern's rates since 1989 suggests that the outcome is very
    uncertain.  Moreover, we disagree that Southwestern would be able to
    absorb the full cost allocated to power and still remain competitive
    even if the pumping units do not operate.  Even if Southwestern has
    the financial capability to absorb these costs, this assertion by
    Southwestern overlooks the policy guidance contained in DOE Order
    RA6120.2, which indicates that if the nonoperational units are not
    put into commercial service, the power customers will not be required
    to repay the investment.  Therefore, if the pumping units remain
    nonoperational, it is irrelevant whether Southwestern could afford to
    absorb the costs.  However, we have added language to appendix VII to
    clarify that if the nonoperational units at Truman do operate
    commercially and are placed into rates, the risk of loss to the
    federal government is remote.

    10.  We correctly stated in our draft report that the Central Valley
    Project (CVP) incurred a net loss of $24 million in fiscal year 1996,
    as evidenced by the "Net Deficit" of over $24 million shown for CVP
    in Western's audited financial statements for that year.  Also, we do
    not agree with the three PMAs' inference that depreciation should not
    be considered an expense.  Although a noncash expense, depreciation
    allocates the costs of fixed assets over their useful lives.
    However, we have added a statement to appendix VII that CVP was able
    to meet its cash flow requirements in fiscal year 1996.

    We believe that the three PMAs have misread our discussion of the
    potential impact of the Central Valley Project Improvement Act
    (CVPIA) on CVP.  We stated that CVPIA emphasizes the need to
    safeguard fish and wildlife and, as a result, less water may be
    available for irrigation, power generation, and other purposes.  We
    go on to state that to the extent that the act's implementation
    reduces power revenues, the uncertainty over the repayment of the
    federal government's investment in CVP's hydropower facilities
    increases.  We did not attempt to predict the act's ultimate impact
    but did describe how the act increases the uncertainty surrounding
    CVP.  Assessing and describing such uncertainty is appropriate when
    assessing the federal government's risk of future financial losses.

    Considering and discussing prices, long-term and short-term, is
    appropriate in a competitive environment.  In our opinion, the
    actions taken by Western to respond to competition (that is,
    decreasing CVP's rates by 26 percent in 1996 and planning to further
    reduce rates by exercising escape clauses in purchase power
    contracts), which our draft report discusses, support this belief.
    Regarding the three PMAs' comment that they could not fully
    understand why we describe the situation at CVP as "uncertain" while
    describing BPA's near-term risk as "remote," the primary difference
    is that BPA has contracts in place that mitigate the federal
    government's risk of future financial losses at BPA for the next few
    years.  Thus, the risk at BPA is remote in the near term.

    We have added language to appendix VII regarding the potential
    reduction in Trinity River water flows to CVP and the impact on the
    federal government's risk of future financial losses at CVP.

    11.  The scope of our work did not include reporting on congressional
    intent regarding the ultimate repayment of the suballocated
    irrigation investment.

    12.  We agree that this investment is early in its repayment period
    and that financial results may change.  However, since project
    expenses have totalled nearly $7.3 million to date, compared to only
    $71,319 in revenues, it will be very difficult to achieve the
    dramatic financial improvement necessary to make the project viable.
    Because of the lack of demand for power from the line, it appears
    unlikely that Western will be able to successfully market its entire
    transmission capacity and recover all relevant costs.  As we report,
    Western officials are discussing blending the line's rate with the
    rate for the older Intertie system, which they believe will increase
    project revenue and provide greater certainty of Mead-Phoenix
    repayment.  However, requiring the Intertie to absorb the
    Mead-Phoenix losses would negatively impact the financial condition
    of the Intertie.  We believe our characterization of the situation as
    a probable loss if the consolidation under consideration cannot be
    successfully implemented is correct.  In addition, we have added
    language to appendix VII clarifying our opinion that even if the
    consolidation can be completed, there is no indication that the
    demand for power from the line will increase or that Western will be
    able to successfully market its transmission capacity.  Therefore,
    under this scenario there is a reasonably possible risk of future
    loss to the federal government.

    13.  We agree with the three PMAs' statement that proposals by
    Western to blend Washoe's power with CVP after 2004 could change the
    risk related to Washoe.  However, blending Washoe's high-cost power
    in with the CVP system would compound the financial difficulties
    facing CVP that we discuss in appendix VII.  We believe that we are
    correct in concluding that as a stand-alone rate-setting system,
    Washoe presents a probable risk of loss of the entire federal
    investment, including deferred payments, of $13 million.  In
    addition, we have added language to appendix VII clarifying that even
    if the consolidation can be completed, the risk to the federal
    government of future financial losses from Washoe is reasonably
    possible, since CVP is itself facing financial difficulties.

    14.  The unique circumstances of the six entities make it unfeasible
    to portray this complex information in tabular form.  The three PMAs'
    proposed table gives a distorted picture of the magnitude of the risk
    by entity.  Additionally, the three PMAs may have misunderstood our
    assessments of risk.  We did not conclude that each problematic
    system represents a probable loss to the federal government.  Rather,
    we concluded that for the three PMAs as a whole, the risk to the
    federal government of some future financial loss is probable.  We
    added language to appendix VII clarifying the overall risk to the
    federal government for the three PMAs and for each of the specific
    problematic projects.

    15.  Although determining the extent to which congressional action
    would be required for the PMAs to recover these costs was beyond the
    scope of our review, we do not believe that specific legislation
    would be necessary in order for all of the categories of unrecovered
    costs to be recovered.  For example, the PMAs could recover the full
    costs associated with Civil Service Retirement System (CSRS) pensions
    and postretirement health benefits by including these costs in rates
    and depositing amounts recovered, like many other PMA ratepayer
    collections, into the General Fund of the Treasury.  This would allow
    the revenue to be available to the Congress to appropriate into the
    Fund to cover the full cost of CSRS pensions and postretirement
    health benefits.

    (See figure in printed edition.)Appendix XII
    COMMENTS FROM THE BONNEVILLE POWER
    ADMINISTRATION
    ========================================================== Appendix IX

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    Now on pp.  17, 18, 28, and 29.

    The following are GAO's comments on the Bonneville Power
    Administration's letter dated June 27, 1997.

    GAO COMMENTS

    1.  Discussed in the "Agency Comments and Our Evaluation" section in
    the letter in volume 1.

    2.  The scope of this assignment did not include examining the public
    benefits that BPA and the other agencies that were the subject of our
    review provide to their respective regions.  However, our report
    states that BPA has substantial financial responsibilities and costs
    with regard to fish and wildlife restoration, irrigation assistance,
    and the provision of power to residential and small farm consumers.
    We have also added a statement to the report's background section
    indicating that these responsibilities are the result of
    congressional mandates.

    Additionally, the report describes in some detail fish costs, the
    related Memorandum of Agreement that is intended to help control
    those costs, and the annual magnitude of these costs.  Specifically,
    the report describes the uncertainty with regard to whether the
    Memorandum of Agreement will be continued beyond 2001 as a factor
    increasing BPA's risk during the post-2001 period.  The report also
    discloses that BPA paid $196 million in fiscal year 1996 to provide
    power to selected residential and small farm consumers and recognizes
    that BPA has an obligation totaling more than $800 million for
    irrigation debt.

    3.  Although we agree that BPA's fish costs constitute significant
    financial exposure, we do not concur with BPA's statement that they
    constitute the "greatest financial exposure apart from market
    prices." This statement ignores BPA's significant debt service
    obligations and the projected upward pressure on other operating
    costs.  These costs, as the report discusses, significantly limit
    BPA's financial flexibility and its ability to meet competitive
    challenges.

    4.  Our report measures the net financing costs of debt outstanding
    at September 30, 1996.  This debt was incurred by BPA from 1951 to
    1996; therefore, using the interest rate for Treasury's overall bond
    portfolio, which includes bonds issued by Treasury over the last 30
    years, is appropriate.  We agree that this rate does not and should
    not reflect "current Treasury borrowing costs nor the rates at which
    Treasury lends to agencies."

    5.  We disagree.  As a result of our analysis, we estimate that the
    fiscal year 1996 net financing cost to the federal government
    resulting from BPA's appropriated debt is $377 million.  As discussed
    in the agency comments section of volume 1, the 9.0 percent interest
    rate on Treasury's outstanding portfolio of long-term bonds is the
    appropriate interest rate to use in estimating the federal
    government's net financing cost because it compares long-term debt to
    long-term debt.  However, even if we had used the 6.7 percent
    interest rate proposed by BPA, the estimated fiscal year 1996 net
    financing cost to the federal government is $223 million, which
    represents a substantial cost to the federal government.

    6.  We believe that BPA's "high interest rate environments" assertion
    is negated by its ability to pay off high interest rate debt first.
    As a result, BPA's average interest rate on appropriated debt at
    September 30, 1996, was 3.5 percent.  This low average interest rate
    results because very little appropriated debt incurred during "high
    interest rate environments" is currently outstanding.  Over 81
    percent of BPA's currently outstanding appropriated debt is at rates
    below 3.5 percent.

    7.  We discussed with cognizant Treasury officials BPA's assertion
    that the interest rates it paid on its Treasury bonds result in a
    markup of roughly 60 to 100 basis points over Treasury's borrowing
    costs.  These officials disagreed with this assessment and noted that
    the difference between Treasury's borrowing costs and the rate BPA
    paid on its Treasury bonds is due primarily to the differences in the
    provisions of the borrowing terms under which each entity obtains
    funds.  Many of BPA's Treasury bonds carry provisions which allow BPA
    to call the debt prior to its maturity, while the long-term bonds
    issued by Treasury generally carry no call provisions.  As a result,
    Treasury bears additional interest rate risk as part of these
    transactions.  According to Treasury officials, these provisions in
    BPA's Treasury bonds increase their value to BPA and require a higher
    interest rate to compensate Treasury for its increased risk.  Thus,
    we continue to believe that the interest rate BPA paid on its
    Treasury bonds results in a reasonable approximation of the federal
    government's cost of providing the funds.

    8.  The characterization of BPA's appropriated debt as of the end of
    fiscal year 1996 and the weighted-average interest rate associated
    with this appropriated debt were taken directly from the audited
    financial statements included in BPA's 1996 annual report.  The
    difference between BPA's appropriated debt after its restructuring as
    shown in our draft report and the figure reported by BPA here relates
    to the treatment of construction work in progress.  Further
    discussion with BPA staff indicates that the correct appropriated
    debt balance is $4.29 billion.  We have changed our report to reflect
    this amount.

    9.  Our review of TVA and BPA appropriated debt entailed an
    examination of whether or not the Treasury was receiving a return
    sufficient to cover its borrowing costs.  Unlike BPA, the terms of
    TVA's appropriated debt require payment of market interest rates on
    all of its appropriations, whether or not they are to be repaid to
    the Treasury.  These rates are reset on an annual basis.  For
    example, in 1982, because of high inflation and resultant high
    interest rates, TVA's weighted-average interest rate on its
    appropriated debt was over 12 percent, while BPA's was approximately
    3.3 percent.  In 1996, TVA paid an interest rate of approximately
    6.87 percent, while BPA's weighted-average interest rate was about
    3.5 percent.  Because TVA is required to pay these market rates of
    interest, which are re-set to Treasury rates every year, the Treasury
    is receiving a return sufficient to cover its borrowing cost.

    10.  We agree that the marketplace is likely to become increasingly
    competitive and that BPA will be subject to considerable market risk
    in the future.  This risk was discussed extensively in our report,
    and was a primary factor in the report's risk analysis.  We agree
    that the prices BPA will be able to charge in the future will be
    driven by market prices; the question is whether the revenues
    received will be adequate to recover all of BPA's costs.  After 2001,
    considerable uncertainty exists with regard to market prices,
    customer contract extensions, and the level of BPA's costs--giving
    rise to our report's conclusion that the risk of loss to the federal
    government after 2001 is "reasonably possible."

    11.  Our draft report stated that the federal government would have
    financial losses if BPA (or the other entities reviewed) was unable
    to repay debt owed to the federal government.  We do not state that
    the entire federal government's financial involvement is likely to be
    lost.  In addition, we added a comment to volume 1 of the final
    report indicating that the power-related assets of BPA or the other
    entities would be available to the federal government to sell to
    offset some portion of any actual losses the federal government
    incurred as a result of its financial involvement with these
    entities.

    12.  We agree that there is uncertainty with regard to implementation
    of the Comprehensive Review's recommendations.  Since these
    recommendations have not been implemented, we did not assess the
    possible effect that they would have on the federal government's
    financial risk.

    13.  We continue to believe that BPA's (and the other PMAs') ability
    to repay the highest interest bearing debt first constitutes a major
    advantage.  This practice has allowed the PMAs (including BPA) to
    keep the weighted-average interest rate on appropriated debt at
    levels that are substantially below any Treasury market interest
    rates that have been in effect for decades.  BPA's fiscal year 1996
    average interest rate on appropriated debt of 3.5 percent is evidence
    of the benefit of the repayment provisions.

    14.  As stated in our report, we compared wholesale average revenue
    per kWh for all entities.

    (See figure in printed edition.)Appendix XIII
    COMMENTS FROM THE TENNESSEE VALLEY
    AUTHORITY
    ========================================================== Appendix IX

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    (See figure in printed edition.)

    The following are GAO comments on TVA's letter dated July 10, 1997.

    GAO COMMENTS

    1.  We agree that TVA's power program is costing the federal
    government about $0.7 million per year for a portion of the pension
    cost for the TVA employees covered by the federal Civil Service
    Retirement System (CSRS).  However, we did not analyze every aspect
    of TVA's program to determine the total cost of TVA to the federal or
    state governments.  As agreed with the requesters and as pointed out
    in both volume 1 and appendix II of volume 2 of our report, our
    review did not (1) estimate the foregone revenue for federal, state,
    or local governments resulting from the tax-exempt status of TVA, (2)
    estimate the foregone revenue for federal and state governments
    resulting from tax-exempt debt instruments issued by TVA, or (3)
    quantify the amount of potential future losses to the federal
    government.  Therefore, we are able to state only that for those
    costs we analyzed, TVA's power program does not result in costs to
    the federal government, except for a small portion of the pension
    costs of TVA employees covered by the CSRS.

    2.  We disagree.  As noted in TVA's comments, as of September 30,
    1996, TVA considered the government's equity in TVA to be
    approximately $4 billion.  This amount consisted of about $608
    million in appropriation investment\1 (referred to as appropriated
    debt in our report) and about $3.4 billion in retained earnings.\2
    Using this definition of the federal government's equity, the federal
    government's "capital invested in TVA prior to 1959" would have been
    limited to the appropriation investment and retained earnings.  TVA
    does not pay the federal government an annual return (interest
    income) on its retained earnings.  It pays an annual return on the
    government's appropriation investment only.  The method for
    calculating this return ensures that the annual payments made by TVA
    result in a return to the federal government that covers its
    borrowing costs.  TVA's comments tend to support our position.  TVA
    stated, "Because the rate at which the annual return payment is
    calculated equals the Treasury's current average cost of money, TVA
    costs the taxpayers nothing."

    3.  Discussed in the "Agency Comments and Our Evaluation" section of
    the letter in volume 1.

    4.  We concur that TVA is required to follow the federal regulations
    that govern the employer and employee contributions for the CSRS and
    therefore, has no control over the pension contribution rules for its
    employees that are covered by this pension plan.  As noted in
    appendix II, in fiscal year 1996, OPM reported that the full (normal)
    cost to the federal government of the pension benefits earned by CSRS
    employees was 25.14 percent of gross salaries.  However, since TVA is
    required to contribute 7 percent and TVA's employees are required to
    contribute another 7 percent, a funding deficiency of 11.14 percent
    (25.14 less 14 percent) of annual salaries existed for each CSRS
    employee.  Since all new federal employees are covered by the FERS
    pension plan, which is fully funded, the future cost to the federal
    government of TVA's CSRS employees should continue to decline.  We
    also concur that the passage of any legislation to increase the
    contributions of the employees and/or employers would decrease the
    cost to the federal government of TVA's CSRS employees.  However,
    because of the present funding shortfall for the CSRS pension plan,
    TVA, like most other government agencies, is not recovering the full
    pension cost for the TVA employees covered by CSRS.

    5.  We agree with TVA that our assessment of the likelihood of loss
    did not consider proceeds that the federal government might receive
    from the sale of TVA's assets.  We discuss this limitation in the
    scope of our review in appendix II of volume 2 of our report.  We
    have added a note to table 3 in volume 1 of our report stating that
    the federal government could sell the power-related assets of RUS
    borrowers, the PMAs, and TVA to offset some portion of any actual
    losses the federal government might incur as a result of its
    financial involvement with these entities.

    6.  We believe the prospects for TVA completing the deferred units as
    nuclear facilities is unlikely, especially given TVA's recently
    issued 10-year business plan that provides no funding for completion
    of these plants.  Even if these units are converted to an alternative
    fuel source, the potential savings over the construction of a new
    plant are very small.  Thus, most of the costs from the deferred
    units are sunk and will not be utilized as nuclear plants or
    converted power plants.  It is unlikely that most, if any, of the
    costs incurred on the deferred units to date will be used directly to
    generate electricity.  Therefore, we continue to believe that TVA
    should apply SFAS No.  90 to the deferred nuclear assets and begin to
    recover these costs immediately.

    If TVA delays recovering the $6.3 billion, while it retains the
    monopoly-like protections described in this report, it could end up
    having to recover these costs from ratepayers when it is facing a
    competitive environment and may not have the ability to set rates at
    a level sufficient to recover all of these costs.  Therefore, TVA's
    continued exclusion of these costs from charges to ratepayers reduces
    the likelihood of recovery from ratepayers and puts the federal
    government at increased risk of absorbing these costs in the future.

    7.  We agree with the facts as stated by TVA, and we believe this
    information supports our point that TVA is subject to interest rate
    risk.  Our report points out that as TVA's approximately $28 billion
    in debt matures, the portion that is not repaid will likely need to
    be refinanced, thus exposing TVA to the risk of rising interest rates
    and even higher financing costs.  As of September 30, 1996, TVA had
    approximately $8 billion in long-term debt that will mature and need
    to be refinanced over the next 5 years.  By the end of this 5-year
    period, for every 1 percentage point change in TVA's borrowing costs
    for that $8 billion, its annual interest expense will increase or
    decrease by $80 million per year.  We also agree with TVA that its
    approximately $2 billion in short-term debt represents additional
    interest rate risk.  We have revised our report to reflect this fact.

    8.  Our report points out that TVA has an inherent cost advantage
    because it operates as a nonprofit and pays substantially less taxes
    than its likely competitors--IOUs.  We agree that as a nonprofit
    operation, TVA would pay little or no income taxes because it has
    minimal net income.  However, the real underlying advantage TVA has
    over IOUs is that it does not have to include a rate of return, which
    results in taxable income, in its electricity rates.  This allows TVA
    to keep its rates proportionately lower than if a rate of return had
    to be generated through revenues.

    TVA also mentioned that to fairly compare the taxes paid by TVA to
    IOUs we should include the taxes paid by TVA's distributors.  We
    agree and have revised our report to reflect this information.  By
    including the taxes paid by TVA's distributors, the percent of taxes
    paid by TVA and its distributors in fiscal year 1995 was about 6
    percent of gross power revenue, which is still substantially less
    than the average annual taxes paid by IOUs.

    9.  The primary objectives of our report were to (1) identify the net
    recurring cost to the federal government from its electricity-related
    activities and (2) assess the risk of future loss to the federal
    government from its indirect and direct involvement in RUS, the PMAs,
    and TVA.  We agree with TVA that as of September 30, 1996, it had
    taken steps to provide adequate funding for two of its significant
    long-term liabilities--decommissioning costs and pensions.
    Therefore, there was no need to include these liabilities in our
    discussion of the net cost to the federal government or risk of
    future losses due to the federal government's involvement in TVA.
    However, TVA's funding for the actual liabilities of these programs
    is contingent upon the accuracy of their assumptions and the extent
    to which future events conform to the schedule used in the
    assumptions.

    --------------------
    \1 TVA's appropriation investment primarily represents appropriations
    received from the federal government prior to 1959 to build capital
    projects.  The 1959 amendments to the TVA Act required TVA to begin
    (1) repaying about $1 billion of the balance of this account and (2)
    paying the federal government an annual market rate of return on the
    unpaid portion of the balance.

    \2 Retained earnings represent the cumulative revenue in excess of
    accrued expenses.  These earnings have been used by TVA primarily to
    finance capital assets.

    MAJOR CONTRIBUTORS TO THIS REPORT
    ========================================================= Appendix XIV

    ACCOUNTING AND INFORMATION
    MANAGEMENT DIVISION, WASHINGTON,
    D.C.

    Gregory D.  Kutz, Associate Director
    McCoy Williams, Assistant Director
    Robert E.  Martin, Senior Audit Manager
    Donald R.  Neff, Senior Audit Manager
    Dianne Langston, Audit Manager
    Patricia B.  Petersen, Auditor
    Meg Mills, Communications Analyst

    OFFICE OF THE GENERAL COUNSEL,
    WASHINGTON, D.C.

    Thomas H.  Armstrong, Assistant General Counsel
    Amy M.  Shimamura, Senior Attorney

    ATLANTA FIELD OFFICE

    William J.  Cordrey, Senior Auditor
    Johnny W.  Clark, Auditor
    Marshall L.  Hamlett, Auditor

    KANSAS CITY FIELD OFFICE

    Arthur W.  Brouck, Senior Auditor
    Christie M.  Arends, Auditor
    Gary T.  Brown, Auditor
    Karen A.  Rieger, Auditor

    SEATTLE FIELD OFFICE

    David W.  Bogdon, Senior Evaluator
    Laurence L.  Feltz, Senior Evaluator

    *** End of document. ***