oversight

Appendixes to The Federal Government's Net Cost and Potential for Future Losses, Volume 2

Published by the Government Accountability Office on 1997-09-19.

Below is a raw (and likely hideous) rendition of the original report. (PDF)

                   United States General Accounting Office

GAO                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
Preface


              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




              Page 1                             GAO/AIMD-97-110A Federal Electricity Activities
Contents



Preface                                                                                               1


Appendix I                                                                                           10
                       Legislative Changes Create a Competitive Electricity Market                   10
Background             The Rural Utilities Service                                                   14
                       Power Marketing Administrations                                               18
                       The Tennessee Valley Authority                                                26

Appendix II                                                                                          31
                       Federal Government’s Direct and Indirect Financial Involvement                32
Objectives, Scope,       in the Electricity-Related Activities at RUS, the PMAs, and TVA
and Methodology        Assessing the Net Cost From Ongoing Operations of                             33
                         Electricity-Related Activities at RUS, the PMAs, and TVA
                       Assessing the Risk to the Federal Government of Future Losses                 46
                         for Electricity-Related Activities
                       Organizations That GAO Contacted                                              52

Appendix III                                                                                         54
                       Average Revenue Per Kilowatthour Is an Indicator of Power                     54
Average Revenue Per      Production Costs
Kilowatthour for
Wholesale Sales
Appendix IV                                                                                          57
                       Net Financing Costs                                                           57
Summary of Net Costs   Loan Write-offs                                                               58
                       Pension and Postretirement Health Benefits                                    58
                       Construction Costs                                                            58
                       Environmental Mitigation Costs                                                59
                       Deferred Payments                                                             59
                       Administrative Appropriations                                                 60
                       Department of Justice Costs                                                   60
                       Irrigation                                                                    60
                       Stores Inventory                                                              61




                       Page 2                            GAO/AIMD-97-110A Federal Electricity Activities
                          Contents




Appendix V                                                                                              62
                          Interest Income                                                               62
Rural Utilities           Interest Expense                                                              63
Service’s Net
Financing Cost
Appendix VI                                                                                             65
                          The Federal Government’s Financial Involvement                                65
Risk Assessment for       Substantial Loan Write-offs Occurred in Recent Years                          65
the Rural Utilities       Additional Losses From Financially Stressed G&T Loans Are                     66
                            Probable in the Short Term
Service Electric          Some Losses From Loans Currently Considered Viable Are                        71
Portfolio                   Probable in the Future

Appendix VII                                                                                            81
                          The Federal Government’s Financial Involvement                                81
Risk Assessment for       The Three PMAs Are Competitively Sound Overall                                83
Southeastern,             Risk of Future Losses From Individual Rate-setting                            98
                            Systems/Projects Is Probable
Southwestern, and
Western
Appendix VIII                                                                                         107
                          The Federal Government’s Financial Involvement                              107
Risk Assessment for       Risk of Loss From BPA Is Remote Through Fiscal Year 2001                    111
the Bonneville Power      Risk of Loss Is Reasonably Possible After Fiscal Year 2001                  114
                          Risk of Loss From Teton Dam Project Is Probable                             126
Administration
Appendix IX                                                                                           128
                          The Federal Government’s Financial Involvement                              128
Risk Assessment for       Risk of Loss From TVA Is Remote Under Current Structure                     130
the Tennessee Valley      Risk of Loss Is Reasonably Possible Absent Protection From                  131
                            Competition
Authority
Appendix X                                                                                            145

Comments From the
Rural Utilities Service




                          Page 3                            GAO/AIMD-97-110A Federal Electricity Activities
                        Contents




Appendix XI                                                                                          150

Comments From
Southeastern,
Southwestern, and
Western
Appendix XII                                                                                         163

Comments From the
Bonneville Power
Administration
Appendix XIII                                                                                        177

Comments From the
Tennessee Valley
Authority
Appendix XIV                                                                                         187

Major Contributors to
This Report
Tables                  Table I.1: Information on the Three PMAs                                       21
                        Table I.2: Information on BPA                                                  24
                        Table I.3: Information on TVA                                                  28
                        Table IV.1: Net Costs for Fiscal Year 1996 and Fiscal Years 1992               57
                          Through 1996 in Constant 1996 Dollars for RUS, TVA, and the
                          PMAs
                        Table V.1: Financing Costs to the Government                                   62
                        Table V.2: Weighted Average Interest Expense for Fiscal Years                  64
                          1992 Through 1996
                        Table VI.1: RUS Financially Stressed G&T Cooperatives, as of                   67
                          September 30, 1996
                        Table VII.1: Federal Government’s Financial Involvement in the                 81
                          Three PMAs as of September 30, 1996 or September 30, 1995
                        Table VII.2: Percentage of Net Power Generation for the PMAs                   94
                          and Other Utilities, 1996




                        Page 4                             GAO/AIMD-97-110A Federal Electricity Activities
          Contents




          Table VIII.1: The Federal Government’s Financial Involvement in             108
            BPA as of September 30, 1996
          Table VIII.2: Percentage of Net Generation for BPA and Other                122
            Utilities, 1996
          Table IX.1: The Federal Government’s Financial Involvement in               128
            the Tennessee Valley Authority as of September 30, 1996
          Table IX.2: Comparison of Financial Ratios for TVA and                      133
            Neighboring IOUs That Indicate Flexibility, Fiscal Year 1996
          Table IX.3: Comparison of Financial Ratios for TVA and                      135
            Neighboring IOUs That Indicate Deferred Assets, Fiscal Year
            1996
          Table IX.4: Percentage of Power Generation From Different                   142
            Sources for TVA and Other Utilities, 1996

Figures   Figure I.1: RUS G&T Borrowers                                                 16
          Figure I.2: Service Areas for Southeastern, Southwestern,                     20
            Western, and BPA
          Figure I.3: Composition of PMA Debt                                           23
          Figure I.4: Composition of BPA’s Total Debt as of September 30,               25
            1996
          Figure I.5: TVA Service Area                                                  27
          Figure I.6: Composition of TVA Debt as of September 30, 1996                  30
          Figure III.1: NERC Regions of the Contiguous United States, as of             56
            1995
          Figure VI.1: Average Revenue per kWh for G&Ts in the                          72
            Southeastern Electric Reliability Council Region
          Figure VI.2: Average Revenue per kWh for G&Ts in the Southwest                73
            Power Pool Region
          Figure VI.3: Average Revenue per kWh for G&Ts in the Electric                 74
            Reliability Council of Texas Region
          Figure VI.4: Average Revenue per kWh for G&Ts in the                          75
            Mid-America Interconnected Network Region
          Figure VI.5: Average Revenue per kWh for G&Ts in the                          76
            Mid-Continent Area Power Pool Region
          Figure VI.6: Average Revenue per kWh for G&Ts in the East                     77
            Central Area Reliability Coordination Agreement Region
          Figure VI.7: Average Revenue per kWh for G&Ts in the Western                  78
            Systems Coordinating Council Region
          Figure VI.8: Average Revenue per kWh for G&Ts in the Alaska                   79
            Systems Coordinating Council Region




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Figure VII.1: Average Revenue per kWh of Wholesale Power Sold,                84
  1995
Figure VII.2: Comparison of Average Revenue per kWh by                        86
  Southeastern Rate-setting System for the SERC Region, 1995
Figure VII.3: Comparison of Average Revenue per kWh by                        87
  Southwestern Rate-setting System for the Southwest Power Pool
  Region, 1995
Figure VII.4: Comparison of Average Revenue per kWh by                        88
  Southwestern Rate-setting System for the Electric Reliability
  Council of Texas Region, 1995
Figure VII.5: Comparison of Average Revenue per kWh by                        89
  Southwestern Rate-setting System for the Mid-Atlantic
  Interconnected Network Region, 1995
Figure VII.6: Comparison of Average Revenue per kWh by                        90
  Western Rate-setting System for the Western Systems
  Coordinating Council Region, 1995
Figure VII.7: Comparison of Average Revenue per kWh by                        91
  Western Rate-setting System for the SPP Region, 1995
Figure VII.8: Comparison of Average Revenue per kWh by                        92
  Western Rate-setting System for the Mid-Continent Area Power
  Pool Region, 1995
Figure VII.9: Comparison of Average Revenue per kWh by                        93
  Western Rate-setting System for the ERCOT Region, 1995
Figure VII.10: Investment in Utility Plant per Megawatt of                    95
  Generating Capacity, 1995
Figure VIII.1: BPA Fish and Wildlife Costs, Fiscal Years 1990-1996          112
Figure VIII.2: Financing Costs as a Percentage of Revenues for              118
  BPA, IOUs, and POGs
Figure VIII.3: Average Revenue per kWh of Wholesale Power                   121
  Sold, 1995
Figure VIII.4: Investment in Utility Plant per Megawatt of                  123
  Generating Capacity
Figure IX.1: Comparison of Investment in PP&E and Retail Rates              138
  Among TVA and Neighboring IOUs

Abbreviations

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


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Contents




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


Page 7                            GAO/AIMD-97-110A Federal Electricity Activities
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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




Page 8                           GAO/AIMD-97-110A Federal Electricity Activities
Page 9   GAO/AIMD-97-110A Federal Electricity Activities
Appendix I

Background


                       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


                       Historically, investor-owned utilities (IOUs) and other electricity providers
Legislative Changes    have operated as regulated monopolies. Under traditional utility
Create a Competitive   regulations, IOUs were generally required to provide electric service to all
Electricity Market     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 plants2 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

                       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.
                       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.



                       Page 10                                        GAO/AIMD-97-110A Federal Electricity Activities
Appendix I
Background




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
Association5 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



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.



Page 11                                         GAO/AIMD-97-110A Federal Electricity Activities
Appendix I
Background




(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.



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.



Page 12                                         GAO/AIMD-97-110A Federal Electricity Activities
                 Appendix I
                 Background




                 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


Stranded Costs   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

                 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.



                 Page 13                                             GAO/AIMD-97-110A Federal Electricity Activities
                      Appendix I
                      Background




                      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 U.S. Department of Agriculture (USDA) is the federal government’s
The Rural Utilities   principal provider of loans used to assist the nation’s rural areas in
Service               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.



                      Page 14                                          GAO/AIMD-97-110A Federal Electricity Activities
                        Appendix I
                        Background




RUS’ Electricity Loan   RUS makes direct loans primarily to construct and maintain electricity
Programs                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.




                        Page 15                              GAO/AIMD-97-110A Federal Electricity Activities
                                        Appendix I
                                        Background




Figure I.1: RUS G&T Borrowers




                                        MT040      ND042           ND020
      OR042
                                                                   ND048
                                                     ND045
                                                                                                                               VT012
                                                                        MN106
                                                          SD043          MN107                    MI046
                                             SD044                                      WI064
                                                                     IA086
                                                                     IA085 IA084                                           PA027
                                                                                IA083
                                                             NE104                               IN107
                                                                         MO072                             OH099
                                        CO047
                                                                                MO070            IN106
                                                                KS054
                                                                          MO071 IL050                     KY059             VA052
                                                        KS053                         KY062
                                                                    MO073 MO059
                                                                           MO060
                                                                  AR032                                                NC067
                                                                                                                   SC051
                                NM018           TX159
                                                             0K032              AR034                               SC050
                                                                                                           GA109
                        AZ028
                                                                   TX158
                                                                                                   AL042
                                                                                         MS053
                                                            TX121 TX154
                                                                  TX157          LA030

                                                            TX148
                                                        TX155                                                        FL041
             AK031
         AK032




                                        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:




                                        Page 16                                                 GAO/AIMD-97-110A Federal Electricity Activities
                            Appendix I
                            Background




                        •   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       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.



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



                            Page 17                                            GAO/AIMD-97-110A Federal Electricity Activities
                  Appendix I
                  Background




                  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.


                  The federal government owns and operates numerous multipurpose dams,
Power Marketing   many of which generate electric power. The power generated at these
Administrations   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 facilities15 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.



                  15
                    Southeastern has no transmission facilities.



                  Page 18                                          GAO/AIMD-97-110A Federal Electricity Activities
Appendix I
Background




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.




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



Page 19                                       GAO/AIMD-97-110A Federal Electricity Activities
                                  
                                          Appendix I
                                          Background




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




                  WA
                                                                                                                                   ME
                                   MT                 ND
             OR
                   BPA                                              MN
                                                                                                                              VT
                                                                                                                                NH
                        ID                                                        WI                                            MA
                                                      SD                                                                 NY
                                                                                                MI                             CT RI
                                     WY

                                                                       IA                                           PA




                                     
                                                       NE                           IL                                        NJ
                   NV
                             UT
                                    WAPA                                                      IN
                                                                                                     OH                  MD
                                                                                                                              DE
                                        CO                                                                  WV
        CA                                            KS
                                                                                                                    VA
                                                                        MO
                                                                                                KY
                                                                                                                    NC
                                                            OK                                 TN
                         AZ                                                 AR
                                     NM
                                                            SWPA                               SEPA           SC

                                                                                              AL       GA
                                                                                       MS
                                                 TX

                                                                            LA

                                                                                                               FL




                                                                     BPA                 Bonneville Power Administration
                                                                     SEPA                Southeastern Power Administration
                                                                     SWPA                Southwestern Power Administration
                                                                     WAPA                Western Area Power Administration


                                                                                 Both Western and Southwestern market power in Kansas.


                                          Source: GAO analysis of data provided by the PMAs.




Role of Southeastern,                     Collectively, Southeastern, Southwestern, and Western sell power
Southwestern, and Western                 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



                                          Page 20                                           GAO/AIMD-97-110A Federal Electricity Activities
                                             Appendix I
                                             Background




                                             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
                                                    Number of
                                                  hydroelectric         Number of        kWh sold              Revenue (in              Miles of
                                                        plants          customers (billions) fiscal          millions) fiscal      transmission
                              Year created          Sept. 1995          Sept. 1995       year 1995                 year 1995               lines
Southeastern                         1950                     23                 296                  6.8                $159                none
Southwestern                         1943                     24                   95                 7.7                 114               1,380
Western                              1977a                    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                The Reclamation Project Act of 1939 and the Flood Control Act of 1944
Recovered Through Rates                    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

                                             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.



                                             Page 21                                        GAO/AIMD-97-110A Federal Electricity Activities
             Appendix I
             Background




             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 debt19), 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.

PMAs’ Debt   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




             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.
             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.



             Page 22                                           GAO/AIMD-97-110A Federal Electricity Activities
                                      Appendix I
                                      Background




                                      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



                                                               •                              2.3%
                                                                                              Nonfederal Debt ($.2 billion)

                                                                    22.7% •                   Irrigation Debt ($1.6 billion)




                                                75.0%
                                                   •




                                                                                              Appropriated Debt ($5.4 billion)



                                      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.


Role of Bonneville Power              BPA was created in 1937 to market electric power from the Bonneville Dam
Administration                        and to construct facilities to transmit the power. It markets electric power

                                      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.



                                      Page 23                                          GAO/AIMD-97-110A Federal Electricity Activities
                                               Appendix I
                                               Background




                                           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
                                                     Number of
                                                   hydroelectric      Number of        kWh sold             Revenue (in              Miles of
                                                         plants       customers (billions) fiscal         millions) fiscal      transmission
                                Year created         Sept. 1995       Sept. 1995       year 1995                year 1995               lines
BPA                                    1937                  29a               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               Unlike the other PMAs, BPA no longer receives an annual appropriation. The
Self-Supporting                            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




                                               Page 24                                    GAO/AIMD-97-110A Federal Electricity Activities
                                         Appendix I
                                         Background




                                         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                               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                                                             Appropriated Debt ($6.8 billion)




                                              • 40%                      41% •            Nonfederal Debt ($7.1 billion)




                                                        14%          •                    5%
                                                          •                               Irrigation Debt ($.8 billion)



                                                                                          Treasury Bonds ($2.5 billion)



                                         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




                                         Page 25                                     GAO/AIMD-97-110A Federal Electricity Activities
                       Appendix I
                       Background




                       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.


                       The Tennessee Valley Authority (TVA) is a multipurpose, independent
The Tennessee Valley   federal corporation established by the Tennessee Valley Authority Act of
Authority              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

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



                       Page 26                                         GAO/AIMD-97-110A Federal Electricity Activities
                                           Appendix I
                                           Background




                                           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




                                                     Kentucky
                                                                                                   Virginia




                                                                               Bristol, VA
                                                           Knoxville
                                  Nashville
                                                                                                 North Carolina
                               Tennessee
                                           Chattanooga
                  Memphis


                                    Huntsville


               Columbus




                                 Alabama                   Georgia


            Mississippi




                                           Source: Developed by GAO from data provided by TVA.




                                           Page 27                                    GAO/AIMD-97-110A Federal Electricity Activities
                                               Appendix I
                                               Background




Table I.3: Information on TVA
                                                      Number of
                                                    hydroelectric         Number of        kWh sold             Revenue (in               Miles of
                                                          plants          customers (billions) fiscal         millions) fiscal       transmission
                                Year created          Sept. 1996          Sept. 1996       year 1996                year 1996                lines
TVA                                    1933                     29a                160b              140.6              $5,693c              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.




Legislation Affecting TVA                  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.




                                               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.



                                               Page 28                                        GAO/AIMD-97-110A Federal Electricity Activities
                           Appendix I
                           Background




                           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.


TVA’s Power Programs Are   As mentioned, TVA’s programs are divided into two types of activities—the
to Be Self-Supporting      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.


TVA’s Debt                 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




                           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.
                           29
                             TVA’s nonpower programs were not included in the scope of this report.



                           Page 29                                          GAO/AIMD-97-110A Federal Electricity Activities
                                         Appendix I
                                         Background




                                         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                                                                             Treasury (FFB) Bonds
                                                                                                  ($3.2 billion)

                                                                                                  2%
                                                                                                  Appropriated Debt ($0.6 billion)




                                                     • 12%




                                                                   86% •                          Public Debt ($24.1 billion)




                                         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.



                                         Page 30                                          GAO/AIMD-97-110A Federal Electricity Activities
Appendix II

Objectives, Scope, and Methodology


              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 cost1
              from ongoing operations of electricity-related activities at the Rural
              Utilities Service (RUS), the Department of Energy’s (DOE) power marketing
              administrations2 (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.



              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.



              Page 31                                         GAO/AIMD-97-110A Federal Electricity Activities
                         Appendix II
                         Objectives, Scope, and Methodology




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


                         Net recurring costs and exposure to additional financial losses result from
Federal Government’s     the federal government’s direct and indirect financial involvement in the
Direct and Indirect      electricity-related activities of these entities. For this report, we defined
Financial Involvement    direct involvement in electricity activities as loans or loan guarantees
                         made by the federal government directly to RUS borrowers and
in the                   appropriated debt4 owed by the PMAs or TVA. As of September 30, 1996, the
Electricity-Related      federal government had over $53 billion of direct financial involvement.
                         The federal government would have financial losses from its direct
Activities at RUS, the   involvement if the RUS borrowers or the federal entity were unable to
PMAs, and TVA            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 BPA5
                         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.



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                         Objectives, Scope, and Methodology




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

                         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.



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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.




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                            Objectives, Scope, and Methodology




Defining the Full Cost of   To define the full costs associated with producing and marketing federal
Producing and Marketing     power and of providing loans and loan guarantees to borrowers, we
Federal Power and of        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
Providing Loans and Loan    costs of providing goods and services. The circular defines full cost as all
Guarantees to Borrowers     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     For this report, we defined the net financing cost to the Treasury as the
Costs                       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



                            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.



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                        used for RUS financing and PMA appropriated debt, TVA’s appropriated debt,
                        TVA’s Federal Financing Bank (FFB) debt, and BPA’s Treasury bonds.



RUS Financing and PMA   We assessed the net financing cost of the RUS loan portfolio and PMA
Appropriated Debt       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 call9
                        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.

RUS Financing           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

                        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.



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                        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   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



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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

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



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                           restructuring. We also did not review the impact of the debt restructuring
                           on the federal budget.

Loan-by-Loan Methodology   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    TVA had outstanding appropriated debt11 and FFB debt and BPA had
and BPA                    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


                           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.



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                          in recovery of a reasonable approximation of the federal government’s
                          cost of providing the funds.


TVA’s Appropriated Debt   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   As of September 30, 1996, TVA had $3.2 billion of long-term debt held by
Bank Debt                 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




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                       Objectives, Scope, and Methodology




                       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.



BPA’s Treasury Bonds   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.



                       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.



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                            Objectives, Scope, and Methodology




                            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   To assess whether pension and postretirement health benefits were fully
Pension and                 recovered by RUS, the PMAs, and TVA, we consulted with representatives
Postretirement Benefits     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

                            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.”



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    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 salary15 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

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



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                            Objectives, Scope, and Methodology




                            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.


Assessing the Recovery of   For this report, we defined other costs to include construction costs for
Other Costs                 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



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Objectives, Scope, and Methodology




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

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



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                            Objectives, Scope, and Methodology




                            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.


                            In assessing the risk of future losses beyond the net recurring costs to the
Assessing the Risk to       federal government from the electricity-related activities at the PMAs, TVA,
the Federal                 and RUS, we used the criteria for contingencies from SFFAS No. 5,
Government of Future        Accounting for Liabilities of the Federal Government. According to SFFAS
                            No. 5, “A contingency is an existing condition, situation, or set of
Losses for                  circumstances involving uncertainty as to possible gain or loss to an entity.
Electricity-Related         The uncertainty will ultimately be resolved when one or more future
                            events occur or fail to occur.” When a loss contingency exists, the
Activities                  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.



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                                Objectives, Scope, and Methodology




                            •   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       In order to assess the risk of future loss beyond the net recurring costs to
the Federal Government          the federal government from the electricity-related activities of RUS, we
for the Rural Utilities         reviewed the $32.3 billion (as of September 30, 1996) RUS portfolio of
                                electric loans and loan guarantees outstanding to rural electric
Service Portfolio of            cooperatives. The portfolio consists of loans and guarantees made to 782
Electric Loans and Loan         distribution cooperatives and 55 Generation and Transmission (G&T)
Guarantees                      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.




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                           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   To assess the risk of future loss beyond the net recurring costs to the
Loss to the Federal        federal government from the electricity-related activities of the PMAs and
                           TVA, we analyzed each agency based on several key factors. We
Government for the PMAs
                           interviewed government bond analysts at Fitch Investors Service and at
and TVA                    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



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Objectives, Scope, and Methodology




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 IOUs18
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.

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).



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    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 rates19 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

    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.



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Objectives, Scope, and Methodology




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



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                       Appendix II
                       Objectives, Scope, and Methodology




                       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.


                       The following are the organizations that GAO contacted during the course
Organizations That     of its work.
GAO Contacted
Federal Agencies       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   Fitch Investors Service, Inc., New York, New York
                       Moody’s Investors Service, New York, New York


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




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                          Objectives, Scope, and Methodology




Electric Utilities or     Entergy, New Orleans, Louisiana
Holding Companies         Southern Company, Atlanta, Georgia

Customer Representative   Direct Service Industries, Inc., Portland, Oregon
or Trade Groups           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          Bristol, Virginia
                          Bristol, Tennessee
                          Chattanooga, Tennessee
                          Four County Electric Power Association, Columbus, Mississippi
                          Fort Payne, Alabama
                          Knoxville, Tennessee
                          Memphis, Tennessee
                          Nashville, Tennessee
                          Paducah, Kentucky




                          Page 53                              GAO/AIMD-97-110A Federal Electricity Activities
Appendix III

Average Revenue Per Kilowatthour for
Wholesale Sales

                      In a competitive market for a relatively homogeneous product like
Average Revenue Per   electricity, being among the lowest cost producers is generally the most
Kilowatthour Is an    important factor in determining competitive position. As the electricity
Indicator of Power    industry responds to deregulation, the ability to keep power production
                      costs low will enhance an entity’s competitive position. To assess power
Production Costs      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



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Appendix III
Average Revenue Per Kilowatthour for
Wholesale Sales




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 councils2 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.




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).



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                                           Appendix III
                                           Average Revenue Per Kilowatthour for
                                           Wholesale Sales




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




                                           Source: North American Electric Reliability Council.




                                           Page 56                                        GAO/AIMD-97-110A Federal Electricity Activities
Appendix IV

Summary of Net Costs


                                          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 financing                   $874                    $377          $68             $42          $98         $1,459                $6,941
Loan write-offs                  982                                                                              982                 1,049
Benefits                            1          $1          21            3             2             11            39                    199
Construction                                                            30                                         30                    139
Environmental                                                                                        28            28                    144
Deferred payments                                                                                  (114)         (114)                   (74)
Administrative
appropriations                    21                                                                               21                    110
DOJ costs                                                                                                                                  1
Irrigation                                                                                           16            16                     80
Stores inventory                                                                                      1              1                     6
Total                         $1,878           $1       $398         $101             $44          $40         $2,462                $8,597
                                          Note: Totals may not add due to rounding.




                                          For RUS, the net financing cost represents the difference between the
Net Financing Costs                       annual interest income received by the federal government from RUS


                                          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).



                                          Page 57                                           GAO/AIMD-97-110A Federal Electricity Activities
                        Appendix IV
                        Summary of Net Costs




                        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.



                        RUS has recently written off a substantial dollar amount of loans to rural
Loan Write-offs         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.


                        RUS,  the PMAs, and TVA3 do not recover the full costs to the federal
Pension and             government of providing Civil Service Retirement System (CSRS) pension
Postretirement Health   benefits to current federal employees. Nor do RUS and the PMAs recover the
Benefits                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


                        Construction costs are comprised of interest that is not paid to Treasury
Construction Costs      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

                        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).



                        Page 58                                        GAO/AIMD-97-110A Federal Electricity Activities
                    Appendix IV
                    Summary of Net Costs




                    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.


                    Two projects, the Central Valley Project’s Shasta Dam and the Colorado
Environmental       River Storage Project’s Glen Canyon Dam, have incurred power-related
Mitigation Costs    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.


                    As of September 30, 1996, Western had deferred operations and
Deferred Payments   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.




                    Page 59                            GAO/AIMD-97-110A Federal Electricity Activities
                        Appendix IV
                        Summary of Net Costs




                        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.


                        The annual administrative appropriation to RUS includes salary expenses
Administrative          for RUS employees as well as travel, data processing, and other
Appropriations          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.


                        The DOJ costs primarily represent hours worked by DOJ attorneys on
Department of Justice   litigation related to RUS’ electricity-related activities. In 1996, DOJ attorneys
Costs                   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.


                        Substantial capital costs for hydropower facilities and water storage
Irrigation              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

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



                        Page 60                                       GAO/AIMD-97-110A Federal Electricity Activities
                   Appendix IV
                   Summary of Net Costs




                   $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.


                   Western has maintained an inventory of “stores supplies,” which are spare
Stores Inventory   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.




                   Page 61                            GAO/AIMD-97-110A Federal Electricity Activities
Appendix V

Rural Utilities Service’s Net Financing Cost


                                    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
                                      (FFB/Treasury)                                        2,477               13,396
                                      Debt to private lenders                                 250                1,229
                                    Net financing costs                                     $(874)             $(3,812)



                                    RUS interest income is initially affected by favorable loan rates given to
Interest Income                     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




                                    Page 62                             GAO/AIMD-97-110A Federal Electricity Activities
                   Appendix V
                   Rural Utilities Service’s Net Financing Cost




                   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.


                   The federal government’s annual interest expense on funds provided for
Interest Expense   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.




                   Page 63                                    GAO/AIMD-97-110A Federal Electricity Activities
                                         Appendix V
                                         Rural Utilities Service’s Net Financing Cost




Table V.2: Weighted Average Interest Expense for Fiscal Years 1992 Through 1996
Dollars in millions
                                                       1992              1993               1994            1995              1996
Debt to FFB/Treasury                               $27,881.9        $27,567.8           $27,387.0      $27,855.3         $27,484.6
Weighted average Treasury rate                       .09505            .09323             .09229          .09134            .09012
  Weighted average interest expense                 $2,650.2         $2,570.1            $2,527.5       $2,544.3          $2,476.9

                                         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.




                                         Page 64                                    GAO/AIMD-97-110A Federal Electricity Activities
Appendix VI

Risk Assessment for the Rural Utilities
Service Electric Portfolio

                         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.


                         As of September 30, 1996, the RUS electric loan and loan guarantee
The Federal              portfolio totaled $32.3 billion. The bulk of the portfolio is made up of loans
Government’s             to the Generation and Transmission Cooperatives (G&Ts). The principal
Financial Involvement    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.


                         Under Department of Justice (DOJ) authority, RUS has recently written off a
Substantial Loan         substantial dollar amount of loans to rural electric cooperatives. The total
Write-offs Occurred in   amount of debt written off between fiscal year 1992 and July 31, 1997, is
Recent Years             about $1.5 billion. The most significant write-offs relate to two G&T loans.

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



                         Page 65                                          GAO/AIMD-97-110A Federal Electricity Activities
                      Appendix VI
                      Risk Assessment for the Rural Utilities
                      Service Electric Portfolio




                      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.


                      It is probable that RUS and DOJ will have additional loan write-offs and
Additional Losses     therefore that the federal government will incur further losses in the short
From Financially      term from loans to borrowers that have been identified as financially
Stressed G&T Loans    stressed by RUS management. Borrowers considered financially stressed
                      have either defaulted on their loans, had their loans restructured but are
Are Probable in the   still experiencing financial difficulty, declared bankruptcy, or have
Short Term            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




                      Page 66                                   GAO/AIMD-97-110A Federal Electricity Activities
                                       Appendix VI
                                       Risk Assessment for the Rural Utilities
                                       Service Electric Portfolio




                                       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                Dollars in millions
September 30, 1996                     Borrower                                                                   Total debt outstanding
                                                      a,b
                                       Borrower A                                                                                  $1,619.6
                                       Borrower B                                                                                      167.9
                                       Borrower C                                                                                      103.2
                                       Borrower Db                                                                                     562.3
                                                      b
                                       Borrower E                                                                                      183.3
                                       Borrower Fa,b                                                                                 1,101.2
                                       Borrower Ga,b                                                                                 4,154.8
                                       Borrower Hb                                                                                     313.4
                                                     b
                                       Borrower I                                                                                      354.8
                                       Borrower J                                                                                    1,070.7
                                       Borrower K                                                                                      445.1
                                       Borrower L                                                                                      351.7
                                                         a
                                       Borrower M                                                                                       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


                                       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.



                                       Page 67                                         GAO/AIMD-97-110A Federal Electricity Activities
Appendix VI
Risk Assessment for the Rural Utilities
Service Electric Portfolio




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.



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Appendix VI
Risk Assessment for the Rural Utilities
Service Electric Portfolio




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.



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



Page 69                                        GAO/AIMD-97-110A Federal Electricity Activities
Appendix VI
Risk Assessment for the Rural Utilities
Service Electric Portfolio




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.



Page 70                                   GAO/AIMD-97-110A Federal Electricity Activities
                         Appendix VI
                         Risk Assessment for the Rural Utilities
                         Service Electric Portfolio




                         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.


                         In addition to the financially stressed loans, RUS has loans outstanding to
Some Losses From         G&T borrowers that are currently considered viable by RUS but may become
Loans Currently          stressed in the future due to high costs and competitive or regulatory
Considered Viable Are    pressures. We believe it is probable that the federal government will
                         eventually incur losses on some of these G&T loans.
Probable in the Future
                         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)
                         regions4 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.

                         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.



                         Page 71                                       GAO/AIMD-97-110A Federal Electricity Activities
                                        Appendix VI
                                        Risk Assessment for the Rural Utilities
                                        Service Electric Portfolio




                                        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   6        Cents per kWh
Reliability Council (SERC) Region
                                                                                       5.00              5.09
                                                                           4.97
                                        5
                                                                                              4.37
                                                               4.27

                                        4        3.90




                                        3



                                        2



                                        1



                                        0
                                                   r1




                                                                                                         Gs
                                                                6



                                                                             r9



                                                                                         r8



                                                                                              Us
                                                               r1
                                                 we




                                                                           we



                                                                                       we



                                                                                              IO



                                                                                                        PO
                                                             we
                                             rro




                                                                       rro



                                                                                   rro
                                                         rro
                                            Bo




                                                                      Bo



                                                                                  Bo
                                                        Bo




                                        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).




                                        Page 72                                                      GAO/AIMD-97-110A Federal Electricity Activities
                                                                            Appendix VI
                                                                            Risk Assessment for the Rural Utilities
                                                                            Service Electric Portfolio




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

6     Cents per kWh



5
                                                                                                                                    4.55

                                                                                                          4.12        4.14
4                                                                                           3.93

                                                                              3.49                                                                 3.48
                                                  3.17          3.26
                        3.11        3.16
3                                                                                                                                          2.73
          2.59


2



1



0
                                      r5




                                                                                             5



                                                                                                           9



                                                                                                                        r4




                                                                                                                                     1



                                                                                                                                           Us



                                                                                                                                                    Gs
           0



                         2




                                                   9



                                                                 8



                                                                               7




                                                                                                          r2




                                                                                                                                    r3
          r2



                        r3




                                                  r1



                                                                r1



                                                                              r1



                                                                                            r2




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                                rro




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    rro



                  rro




                                            rro



                                                          rro



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                                                                                      rro




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                               Bo




                                                                                                   Bo




                                                                                                                             Bo
Bo



                 Bo




                                           Bo



                                                         Bo



                                                                       Bo



                                                                                     Bo




                                                                            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.




                                                                            Page 73                                                        GAO/AIMD-97-110A Federal Electricity Activities
                                       Appendix VI
                                       Risk Assessment for the Rural Utilities
                                       Service Electric Portfolio




Figure VI.3: Average Revenue per kWh
for G&Ts in the Electric Reliability   6     Cents per kWh
Council of Texas (ERCOT) Region

                                       5
                                                                                           4.55

                                                                             4.09                            4.02
                                                               3.97                               3.97
                                       4
                                                 3.59


                                       3



                                       2



                                       1



                                       0
                                                                                            1



                                                                                                  Us



                                                                                                             Gs
                                                  0



                                                                7



                                                                              8



                                                                                           r3
                                                 r3



                                                               r2



                                                                             r2




                                                                                                  IO



                                                                                                            PO
                                            we



                                                             we



                                                                           we



                                                                                         we
                                                                                     rro
                                           rro



                                                         rro



                                                                       rro



                                                                                    Bo
                                       Bo



                                                        Bo



                                                                      Bo




                                       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.




                                       Page 74                                                           GAO/AIMD-97-110A Federal Electricity Activities
                                       Appendix VI
                                       Risk Assessment for the Rural Utilities
                                       Service Electric Portfolio




Figure VI.4: Average Revenue per kWh
for G&Ts in the Mid-America            5     Cents per kWh
Interconnected Network (MAIN) Region
                                                 4.17
                                       4                       3.87




                                       3
                                                        2.53



                                       2




                                       1




                                       0
                                                  0



                                                        Us



                                                                Gs
                                                 r1



                                                        IO



                                                               PO
                                            we
                                           rro
                                       Bo




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




                                       Page 75                                    GAO/AIMD-97-110A Federal Electricity Activities
                                                                              Appendix VI
                                                                              Risk Assessment for the Rural Utilities
                                                                              Service Electric Portfolio




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

5     Cents per kWh




4
                                                                                              3.70          3.66
                                                                                3.52
                                                                                                                          3.24
                                                    3.12          3.13
                        2.94          3.00
3         2.82

                                                                                                                   2.37


2




1




0
                                                                                               5



                                                                                                             6



                                                                                                                   Us



                                                                                                                           Gs
                                                     4



                                                                   2



                                                                                 3
           1



                         3



                                       2




                                                                                                            r2
                                                                  r1



                                                                                r3



                                                                                              r1
          r2



                        r2



                                      r2



                                                    r1




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                                                                         Bo



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                                                                                                     Bo
Bo



                 Bo



                               Bo



                                             Bo



                                                           Bo




                                                                              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.




                                                                              Page 76                                            GAO/AIMD-97-110A Federal Electricity Activities
                                       Appendix VI
                                       Risk Assessment for the Rural Utilities
                                       Service Electric Portfolio




Figure VI.6: Average Revenue per kWh
for G&Ts in the East Central Area      Cents per kWh
Reliability Coordination Agreement     4                                     3.88
(ECAR) Region
                                                               3.48

                                                                                           3.13
                                                 2.99
                                       3
                                                                                    2.72




                                       2




                                       1




                                       0
                                                                                    Us



                                                                                            Gs
                                                  3



                                                                4



                                                                              1
                                                 r1



                                                               r2



                                                                             r1



                                                                                    IO



                                                                                           PO
                                            we



                                                             we



                                                                           we
                                           rro



                                                         rro



                                                                       rro
                                       Bo



                                                        Bo



                                                                      Bo




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




                                       Page 77                                                    GAO/AIMD-97-110A Federal Electricity Activities
                                       Appendix VI
                                       Risk Assessment for the Rural Utilities
                                       Service Electric Portfolio




Figure VI.7: Average Revenue per kWh
for G&Ts in the Western Systems        6     Cents per kWh
Coordinating Council (WSCC) Region

                                       5
                                                                         4.69


                                                             4.06
                                       4
                                                 3.66

                                                                                3.19   3.26

                                       3



                                       2



                                       1



                                       0
                                                                           r6



                                                                                Us



                                                                                        Gs
                                                  6



                                                               r7
                                                 r2



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                                                                    Bo
                                       Bo




                                       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.




                                       Page 78                                                GAO/AIMD-97-110A Federal Electricity Activities
                                       Appendix VI
                                       Risk Assessment for the Rural Utilities
                                       Service Electric Portfolio




Figure VI.8: Average Revenue per kWh
for G&Ts in the Alaska Systems         5        Cents per kWh
Coordinating Council (ASCC) Region
                                                            4.43


                                       4

                                                3.33
                                                                   3.19
                                       3




                                       2




                                       1




                                       0
                                                  r2



                                                              r3



                                                                    Gs
                                                we



                                                            we



                                                                   PO
                                            rro



                                                        rro
                                           Bo



                                                       Bo




                                       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.




                                       Page 79                                     GAO/AIMD-97-110A Federal Electricity Activities
Appendix VI
Risk Assessment for the Rural Utilities
Service Electric Portfolio




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.




Page 80                                   GAO/AIMD-97-110A Federal Electricity Activities
Appendix VII

Risk Assessment for Southeastern,
Southwestern, and Western

                                     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).


                                     The federal government has substantial financial involvement in the
The Federal                          activities of the three PMAs. As shown in table VII.1, the federal
Government’s                         government’s direct financial involvement, which consists of appropriated
Financial Involvement                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   Dollars in millions
PMAs as of September 30, 1996 or                                                 Direct                       Indirect
September 30, 1995
                                                                    Appropriated             Irrigation        Nonfederal
                                     PMA                                    debt                   debt             debt             Total
                                     Southeastern                           $1,491a                                                 $1,491
                                     Southwestern                               686a                                                  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.




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



                                     Page 81                                          GAO/AIMD-97-110A Federal Electricity Activities
                     Appendix VII
                     Risk Assessment for Southeastern,
                     Southwestern, and Western




Direct Financial     Appropriated debt consists of appropriations, which must be repaid with
Involvement          interest, primarily used to construct the generating and transmission
                     facilities2 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 legislation3 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.


Indirect Financial   The federal government’s indirect financial involvement, which consists of
Involvement          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.




                     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).



                     Page 82                                           GAO/AIMD-97-110A Federal Electricity Activities
                          Appendix VII
                          Risk Assessment for Southeastern,
                          Southwestern, and Western




                          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 market power that is substantially lower in cost than
The Three PMAs Are        power sold by nonfederal utilities, which indicates that they are currently
Competitively Sound       competitively sound overall. The PMAs’ low average revenue per
Overall                   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.


Average Revenue per kWh   Overall, the three PMAs’ average revenue per kWh were more than
Has Been Substantially    40 percent below those of other nonfederal utilities for 1995. Moreover,
                          GAO previously found6 that the three PMAs’ average revenue per kWh were
Lower Than Nonfederal
                          consistently 40 percent or more below nonfederal utilities for the years
Utilities                 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




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



                          Page 83                                          GAO/AIMD-97-110A Federal Electricity Activities
                                        Appendix VII
                                        Risk Assessment for Southeastern,
                                        Southwestern, and Western




                                        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           6   Cents per kWh


                                                          5.09
                                        5
                                                   4.37

                                        4
                                                                                3.48
                                                                                              3.19 3.26
                                        3                                2.73

                                            2.27

                                        2                                              1.87

                                                                  1.33

                                        1



                                        0

                                              SEPA/SERC            SWPA/SPP              WAPA/WSCC
                                              PMAs and utility groups



                                                           PMAs

                                                           IOUs

                                                           POGs



                                        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).



                                        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.



                                        Page 84                                           GAO/AIMD-97-110A Federal Electricity Activities
Appendix VII
Risk Assessment for Southeastern,
Southwestern, and Western




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 systems8
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.




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.



Page 85                                         GAO/AIMD-97-110A Federal Electricity Activities
                                      Appendix VII
                                      Risk Assessment for Southeastern,
                                      Southwestern, and Western




Figure VII.2: Comparison of Average
Revenue per kWh by Southeastern       6    Cents per kWh
Rate-setting System for the SERC
Region, 1995                                                                                         5.09
                                      5
                                                                                          4.37

                                      4



                                               2.88                                2.96
                                      3
                                                       2.57


                                      2

                                                                      1.34

                                      1



                                      0
                                                C



                                                           ff



                                                                       d



                                                                                   ott



                                                                                          Us



                                                                                                     Gs
                                                                      an
                                                       ru
                                           L/S




                                                                                  ilp



                                                                                          IO



                                                                                                    PO
                                                       od



                                                                     erl
                                           /A




                                                                              Ph
                                                      Wo



                                                                 mb
                                          GA




                                                                             rr-
                                                                Cu



                                                                             Ke




                                      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.




                                      Page 86                                                    GAO/AIMD-97-110A Federal Electricity Activities
                                          Appendix VII
                                          Risk Assessment for Southeastern,
                                          Southwestern, and Western




Figure VII.3: Comparison of Average
Revenue per kWh by Southwestern           4        Cents per kWh
Rate-setting System for the Southwest
                                                                   3.48
Power Pool (SPP) Region, 1995

                                          3
                                                            2.73




                                          2


                                                   1.34


                                          1




                                          0
                                                    m



                                                            Us



                                                                    Gs
                                                   ste



                                                           IO



                                                                   PO
                                               Sy
                                              ed
                                          rat
                                         eg
                                        Int




                                          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.




                                          Page 87                                     GAO/AIMD-97-110A Federal Electricity Activities
                                         Appendix VII
                                         Risk Assessment for Southeastern,
                                         Southwestern, and Western




Figure VII.4: Comparison of Average
Revenue per kWh by Southwestern          5        Cents per kWh
Rate-setting System for the Electric
Reliability Council of Texas (ERCOT)
Region, 1995                                                               3.97   4.02
                                         4




                                         3




                                         2

                                                  1.34

                                                           0.98    0.97
                                         1




                                         0
                                                   m



                                                           llis




                                                                       n



                                                                           Us



                                                                                   Gs
                                                                   ur
                                                  ste




                                                                           IO



                                                                                  PO
                                                          Wi



                                                                  yb
                                              Sy




                                                                  Ra
                                             ed
                                         rat
                                        eg
                                       Int




                                         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.




                                         Page 88                                         GAO/AIMD-97-110A Federal Electricity Activities
                                        Appendix VII
                                        Risk Assessment for Southeastern,
                                        Southwestern, and Western




Figure VII.5: Comparison of Average
Revenue per kWh by Southwestern         5        Cents per kWh
Rate-setting System for the
Mid-Atlantic Interconnected Network
(MAIN) Region, 1995                     4                        3.87




                                        3
                                                          2.53



                                        2

                                                 1.34

                                        1




                                        0
                                                  m



                                                          Us



                                                                  Gs
                                                 ste



                                                         IO



                                                                 PO
                                             Sy
                                            ed
                                        rat
                                       eg
                                      Int




                                        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.




                                        Page 89                                     GAO/AIMD-97-110A Federal Electricity Activities
                                                                      Appendix VII
                                                                      Risk Assessment for Southeastern,
                                                                      Southwestern, and Western




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

4    Cents per kWh


                                                                                                                        3.26
                                                                                                                 3.19

3

                           2.55


                    2.13                                 2.12
2                                            1.82                                               1.81



      1.24
                                                                      1.13        1.10
                                                                                                          0.99
1




0
                                                                                   r
    Ca lder
          on


                    AZ




                            P



                                              d



                                                          d



                                                                       is




                                                                                                   ity



                                                                                                          oe



                                                                                                                 Us



                                                                                                                         Gs
                                                                                  ive
                                             sta



                                                     lan
                           CV




                                                                      av




                                                                                              eC




                                                                                                          sh
       ny




                                                                                                                 IO



                                                                                                                        PO
                    al




                                                                              oR
       u




                                                                     r-D
                                        mi



                                                    ve




                                                                                                         Wa
    Bo



               ntr




                                                                                              ak
                                                    Lo
                                       n-A




                                                                rke




                                                                             ov
               Ce




                                                                                         lt L
                                                                             Pr
                                  lco




                                                                Pa




                                                                                         Sa
                                  Fa




                                                                      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.




                                                                      Page 90                                           GAO/AIMD-97-110A Federal Electricity Activities
                                      Appendix VII
                                      Risk Assessment for Southeastern,
                                      Southwestern, and Western




Figure VII.7: Comparison of Average
Revenue per kWh by Western            4    Cents per kWh
Rate-setting System for the SPP
                                                             3.48
Region, 1995

                                      3
                                                      2.73



                                               2.12
                                      2




                                      1




                                      0
                                                d



                                                      Us



                                                              Gs
                                           lan



                                                      IO



                                                             PO
                                          ve
                                          Lo




                                      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.




                                      Page 91                                     GAO/AIMD-97-110A Federal Electricity Activities
                                      Appendix VII
                                      Risk Assessment for Southeastern,
                                      Southwestern, and Western




Figure VII.8: Comparison of Average
Revenue per kWh by Western            4         Cents per kWh
Rate-setting System for the
Mid-Continent Area Power Pool
                                                                3.24
(MAPP) Region, 1995
                                      3


                                                         2.37


                                      2

                                                1.52



                                      1




                                      0
                                                 n



                                                         Us



                                                                 Gs
                                                loa



                                                        IO



                                                                PO
                                           k-S
                                          Pic




                                      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.




                                      Page 92                                     GAO/AIMD-97-110A Federal Electricity Activities
                                      Appendix VII
                                      Risk Assessment for Southeastern,
                                      Southwestern, and Western




Figure VII.9: Comparison of Average
Revenue per kWh by Western            5      Cents per kwh
Rate-setting System for the ERCOT
Region, 1995
                                                        3.97   4.02
                                      4




                                      3




                                      2          1.82




                                      1




                                      0
                                                  d



                                                        Us



                                                                Gs
                                                 sta



                                                        IO



                                                               PO
                                            mi
                                           n-A
                                      lco
                                      Fa




                                      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.




Cost Recovery Structure               As noted in volume 1 of this report and in our September 1996 report,10 the
and Inherent Advantages               three PMAs do not recover all costs associated with producing and
Contribute to Low-cost                marketing federal hydropower. These unrecovered costs include net
                                      financing costs, Civil Service Retirement System (CSRS) pension and
Power                                 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



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



                                      Page 93                                       GAO/AIMD-97-110A Federal Electricity Activities
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                                       Risk Assessment for Southeastern,
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                                       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                                                       Net power generated (percent)
Utilities, 1996                                                               Coal        Nuclear          Gas        Hydro         Other
                                       Three PMAs                               6.6a             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.




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                                       Risk Assessment for Southeastern,
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Figure VII.10: Investment in Utility
Plant per Megawatt of Generating       1400     Dollars in thousands
Capacity, 1995
                                       1200
                                                                               1125
                                                                                       1065

                                       1000


                                        800

                                                639
                                        600
                                                          512          496

                                        400


                                        200


                                            0

                                                  SEPA     SWPA         WAPA    IOUs    POGs



                                       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.


                                       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.



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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 study14 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

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.



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                              Risk Assessment for Southeastern,
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                              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.


Management Actions and        The three PMAs have taken action to enhance their ability to compete.
the Nature of Customer        However, because the U.S. Army Corps of Engineers (Corps) and the
Contracts Contribute to       Bureau of Reclamation (Bureau) operate federal projects, many capital
                              and operating costs are beyond the control of the PMAs.
the Overall Sound
Competitive Position of the   Southeastern, unlike Southwestern and Western, does not own any
Three PMAs                    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



                              Page 97                             GAO/AIMD-97-110A Federal Electricity Activities
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                        Risk Assessment for Southeastern,
                        Southwestern, and Western




                        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.


                        Although the three PMAs are currently competitively sound overall, we
Risk of Future Losses   identified situations at one or a few projects or rate-setting systems at
From Individual         each of the three PMAs that, taken as a whole, indicate that it is probable
Rate-setting            that the federal government will incur some future financial losses from
                        one or more of the three PMAs’ projects. The federal government, to
Systems/Projects Is     varying degrees, is at risk of losing at least some of its investment in six
Probable                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            To date, about one-half of the cost of constructing the Richard B. Russell
                        Project16 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

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



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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

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.



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               Risk Assessment for Southeastern,
               Southwestern, and Western




               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 advantage19 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


Southwestern   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

               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.
               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.



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Risk Assessment for Southeastern,
Southwestern, and Western




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.



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



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                         Risk Assessment for Southeastern,
                         Southwestern, and Western




                         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 million24 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 advantage25 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.


Western
Central Valley Project   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


                         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.
                         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.



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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



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                            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 investment28 in CVP.

Pick-Sloan Missouri Basin   The Pick-Sloan Missouri Basin Program (Pick-Sloan) is a comprehensive
Program                     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 million32 investment.

Mead-Phoenix Transmission   Another project with questionable financial viability is the Mead-Phoenix
Line                        Transmission Line. Mead-Phoenix was recently added to the Pacific
                            Northwest-Pacific Southwest Intertie (Transmission) Project intended to

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



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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 million34 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


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.



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                 capacity, resulting in a reasonably possible risk of future loss to the
                 federal government.

Washoe Project   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 million35 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.



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Risk Assessment for the Bonneville Power
Administration

                        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 has substantial direct and indirect financial
The Federal             involvement in the activities of BPA. The direct involvement relates to BPA’s
Government’s            appropriated debt, Treasury bonds, and irrigation debt.1 For all three
Financial Involvement   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.




                        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.



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Table VIII.1: The Federal Government’s
Financial Involvement in BPA as of       Dollars in billions
September 30, 1996                                                                                  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



Direct Financial                         BPA’s appropriated debt consists of appropriations primarily used to
Involvement                              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




                                         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.



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financing cost4 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



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.



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                     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.


Indirect Financial   BPA had nonfederal debt of about $7.1 billion at September 30, 1996. This
Involvement          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.



                     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).



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                          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.


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

2001
Customer Contracts        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   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




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                                       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          Dollars in millions
                                       400




                                       300




                                       200




                                       100




                                         0

                                          1990               1991   1992            1993          1994         1995          1996

                                          Year




                                       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.




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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 Council8
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.



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.



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                             Administration




                             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.


Financial Reserves           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.


                             Because of risks from the expiration of customer contracts, market
Risk of Loss Is              uncertainties, BPA’s high fixed costs, and upward pressure on other
Reasonably Possible          expenses, the risk of loss to the federal government increases significantly
After Fiscal Year 2001       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           In fiscal year 2001, nearly all of BPA’s power contracts with customers will
Expire in Fiscal Year 2001   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


                             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.



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                               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          BPA faces substantial risk from the uncertainties of the wholesale
Market Uncertainties           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   One of the key market uncertainties that will determine whether cheaper
and Surplus Power              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



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                                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 costs10
                                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.

Effects of Retail Open Access   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

                                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.



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                              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   BPA faces substantial risk beyond fiscal year 2001 because a large portion
Costs Continue                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.




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Figure VIII.2: Financing Costs as a
Percentage of Revenues for BPA,       35   Percent
IOUs, and POGs                               32

                                      30


                                      25


                                      20
                                                             18

                                                     15
                                      15


                                      10


                                       5


                                       0

                                              BPA     IOUs    POGs



                                      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



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                               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   Several factors combine to increase the financial pressure faced by BPA in
Other Expenses After Fiscal    the period beyond fiscal 2001. Among them are the expiration of the fish
Year 2001                      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



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                               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      Several factors mitigate the federal government’s risk of loss from BPA.
Long-term Probability of       These factors include inherent cost advantages, management actions that
Loss                           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    As shown in figure VIII.3, in 1995 BPA’s average revenue per kWh was more
Inherent Advantages            than 15 percent lower than IOUs and POGs in the primary North American
Contribute to Low-Cost Power   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.

                               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.



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Figure VIII.3: Average Revenue per
kWh of Wholesale Power Sold, 1995
(Revenues in cents)                  4    Cents per kWh



                                                          3.19        3.26

                                     3
                                         2.71


                                                 2.18

                                     2




                                     1




                                     0

                                          BPA              IOUs         POGs



                                                  1995

                                                  1996


                                     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.




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Table VIII.2: Percentage of Net
Generation for BPA and Other Utilities,                                             Coal        Nuclear           Gas         Hydro          Other
1996                                      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.




                                          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.



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Figure VIII.4: Investment in Utility Plant
per Megawatt of Generating Capacity          1400   Dollars in thousands


                                             1200
                                                              1125
                                                                           1065

                                             1000

                                                    823
                                              800


                                              600


                                              400


                                              200


                                                0

                                                      BPA      IOUs         POGs



                                             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



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                     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 study14 of 670
                     public distribution utilities showed that the median net payments and
                     contributions as a percentage of electric operating revenue were
                     5.8 percent.

Management Actions   BPA management has taken several actions that are intended to address the
                     intense wholesale electricity competition in the Pacific Northwest. These


                     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.



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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.



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Transmission System    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.


                       We identified one small project that serves BPA for which we believe
Risk of Loss From      financial loss to the federal government is probable. This project, Teton
Teton Dam Project Is   Dam, was a multipurpose project on the Teton River in Idaho built by the
Probable               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.



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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.




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Risk Assessment for the Tennessee Valley
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                                       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.


                                       The federal government has financial exposure because of its nearly
The Federal                            $28 billion of direct and indirect financial involvement with TVA. As shown
Government’s                           in table IX.1, the federal government’s direct financial involvement, which
Financial Involvement                  consists of appropriated debt2 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           Dollars in billions
Tennessee Valley Authority as of                                                                   Financial involvement
September 30, 1996
                                       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.




                                       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.
                                       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.



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Direct Financial     TVA’s appropriated debt consists of appropriations that were primarily
Involvement          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 return3 (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
                     TVAfailed to make payments on its outstanding appropriated and FFB debt.


Indirect Financial   Like its FFB debt, TVA’s authority to issue public debt stems from the
Involvement          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

                     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.



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                        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.


                        We believe there are two major factors that protect TVA from competition
Risk of Loss From       and result in TVA operating in a manner similar to a traditional regulated
TVA Is Remote Under     electric utility monopoly. First, in nearly all instances, TVA’s contracts with
Current Structure       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     TVA’s wholesale contracts with its 160 distributors, representing 83 percent
Provide Stability and   of TVA’s load, are generally long-term, which assure it a relatively stable
Ensured Cash Flow       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.




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                           Risk Assessment for the Tennessee Valley
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TVA’s Exemption From       TVA is further insulated from competition by a specific exemption from
“Wheeling” Provisions      wheeling provisions of the Energy Policy Act of 1992. Under the act’s
Protects Against Outside   provisions, the Federal Energy Regulatory Commission (FERC) can
                           generally compel a utility to transmit (“wheel”) electricity generated by
Competition                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     Another significant advantage for TVA is that unlike other utilities, the rates
Minimum Oversight          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.


                           Based on discussions with industry experts and TVA officials, it appears
Risk of Loss Is            unlikely that TVA will be allowed to maintain its current regulated
Reasonably Possible        monopoly-type structure indefinitely and, at some future point, will have
Absent Protection          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
From Competition           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.




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High Fixed and Deferred     TVA has chosen to defer costs related to its substantial nuclear investment
Assets Would Impede TVA’s   to future years rather than currently including them among the costs being
Ability to Compete          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          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

                            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.



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                                         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                                                                                          Fixed financing
That Indicate Flexibility, Fiscal Year                                                        Financing costs to            costs to revenue
1996                                     Utility                                               revenue (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.


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



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                        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.


Deferred Asset Ratios   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.




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Table IX.3: Comparison of Financial
Ratios for TVA and Neighboring IOUs                                                                 Accumulated
That Indicate Deferred Assets, Fiscal                                                               depreciation/
Year 1996                                                                                          amortization to        Deferred assets
                                                                                                     gross PP&E            to 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


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



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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 units7). 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.




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.



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                         Appendix IX
                         Risk Assessment for the Tennessee Valley
                         Authority




                         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.


Investment in PP&E Per   Finally, to analyze TVA’s competitiveness with its 11 neighboring utilities,
Megawatt of Generating   we compared the investment in PP&E per megawatt of generating
Capacity                 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




                         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.



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                                                                         Appendix IX
                                                                         Risk Assessment for the Tennessee Valley
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Figure IX.1: Comparison of Investment in PP&E and Retail Rates Among TVA and Neighboring IOUs

1,500     Dollars (in thousands)
                                                                                                                                         Cents per kWh             11
                                                                                                  1,387

        1,283                                                                       1,282                                                                          10
                                                                                                                                        1,245
                                                                                                                                                                   9
                                                          1,077
                                                                                                                                                                   8
1,000
                                  937                                                                     7.0
                                        6.5                       6.5                                                                                  887         7
                                                                                            6.4
                      823                                                                                                   828
                                                                        781                                                                                  6.0
                                              764                                                                                               5.8                6
                                                                              5.6
                                                    5.4
                5.3
                            5.0                                                                                                   5.0
                                                                                                                637                                                5
                                                                                                                      4.2
                                                                                                                                                                   4
 500

                                                                                                                                                                   3

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         Utility company

                       Investment in PP&E per megawatt of generating capacity in thousands of dollars

                       Average system retail rates (in cents per kWh)



                                                                         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




                                                                         Page 138                                                            GAO/AIMD-97-110A Federal Electricity Activities
                       Appendix IX
                       Risk Assessment for the Tennessee Valley
                       Authority




                       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.


TVA Faces Some         While TVA’s wholesale rates look relatively competitive in the Southeast,
Competitive Pressure   we believe TVA’s competitive position will be weakened when it begins to
Today                  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



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                        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     In addition to TVA’s high fixed and deferred assets, we believe the
Negatively Affect TVA   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



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                            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.


Mitigating Factors Reduce   TVA has a number of factors that mitigate its high fixed and deferred assets.
Risk of Loss                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    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


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



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                                        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   Utility                                 Coal        Nuclear           Gas        Hydro          Other
TVA and Other Utilities, 1996           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

Management Actions and Plans            Recently, TVA has taken a number of steps to reduce its operating and
to Reduce Costs and Increase            capital expenses and become more competitive. For example, it canceled
Revenues                                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


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



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                                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   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



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legal, political, and commercial uncertainties regarding the possibility of
recovering stranded costs.




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Comments From the Rural Utilities Service


Note: GAO comments
supplementing those in the
report text appear at the
end of this appendix.




See comment 1.




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See comment 2.




See comment 1.




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See comment 3.




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


               1. Our April 1997 report presented information on the financial condition
GAO Comments   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.”




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




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Southwestern, and Western

Note: GAO comments
supplementing those in the
report text appear at the
end of this appendix.




See comment 1.




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See comment 2.




See comment 1.




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See comment 3.




See comment 4.




See comment 5.




See comment 1.




See comment 6.




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See comment 7.




Now on p. 29.




See comment 8.




See comment 9.




See comment 10.




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See comment 11.




See comment 12.




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See comment 13.




See comment 14.




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See comment 15.
Now on p. 4.




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


               1. Discussed in the “Agency Comments and Our Evaluation” section in the
GAO Comments   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.




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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



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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.




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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.




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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




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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.




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Comments From the Bonneville Power
Administration

Note: GAO comments
supplementing those in the
report text appear at the
end of this appendix.




See comment 1.




See comments 2 and 3.




See comment 1.




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                 Administration




See comment 1.




See comment 1.




See comment 1.




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                 Administration




See comment 4.




See comment 1.




See comment 5.




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                 Administration




See comment 1.




See comment 1.




See comment 6.




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                 Administration




See comment 1.




See comment 7.




See comment 1.




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                        Comments From the Bonneville Power
                        Administration




See comment 1.




See comment 2.



Now on pp. 24 and 25.




See comment 8.


See comment 9.




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                  Administration




See comment 2.




See comment 10.




See comment 10.




See comment 1.




See comment 11.




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                            Comments From the Bonneville Power
                            Administration




See comment 11.




Now in app. VIII, p. 110.


See comment 1.




See comment 12.




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                  Comments From the Bonneville Power
                  Administration




See comment 13.




See comment 1.




See comment 1.




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                         Appendix XII
                         Comments From the Bonneville Power
                         Administration




See comment 14.
Now on pp. 17, 18, 28,
and 29.




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               Appendix XII
               Comments From the Bonneville Power
               Administration




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


               1. Discussed in the “Agency Comments and Our Evaluation” section in the
GAO Comments   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.”




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Comments From the Bonneville Power
Administration




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



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Comments From the Bonneville Power
Administration




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




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Comments From the Bonneville Power
Administration




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.




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Appendix XIII

Comments From the Tennessee Valley
Authority

Note: GAO comments
supplementing those in the
report text appear at the
end of this appendix.




See comment 1.



See comment 2.




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                 Comments From the Tennessee Valley
                 Authority




See comment 3.




See comment 4.




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                 Authority




See comment 5.




See comment 3.




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                 Authority




See comment 6.




See comment 7.




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                 Authority




See comment 3.




See comment 8.




See comment 9.




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Comments From the Tennessee Valley
Authority




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               Authority




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


               1. We agree that TVA’s power program is costing the federal government
GAO Comments   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 investment1
               (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.


               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.



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Comments From the Tennessee Valley
Authority




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



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Comments From the Tennessee Valley
Authority




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



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Comments From the Tennessee Valley
Authority




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.




Page 186                             GAO/AIMD-97-110A Federal Electricity Activities
Appendix XIV

Major Contributors to This Report


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


                        Thomas H. Armstrong, Assistant General Counsel
Office of the General   Amy M. Shimamura, Senior Attorney
Counsel, Washington,
D.C.
                        William J. Cordrey, Senior Auditor
Atlanta Field Office    Johnny W. Clark, Auditor
                        Marshall L. Hamlett, Auditor


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


                        David W. Bogdon, Senior Evaluator
Seattle Field Office    Laurence L. Feltz, Senior Evaluator




(913805)                Page 187                             GAO/AIMD-97-110A Federal Electricity Activities
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