oversight

Federal Electricity Activities: The Federal Government's Net Cost and Potential for Future Losses, Volume 1

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
                  The Federal Government’s
                  Net Cost and Potential for
                  Future Losses

                  Volume 1




GAO/AIMD-97-110
      United States
GAO   General Accounting Office
      Washington, D.C. 20548

      Accounting and Information
      Management Division

      B-276640

      September 19, 1997

      The Honorable John R. Kasich
      Chairman
      Committee on the Budget
      House of Representatives

      The Honorable John T. Doolittle
      Chairman, Subcommittee on Water
        and Power Resources
      Committee on Resources
      House of Representatives

      This two-volume report responds to your December 13, 1996, and
      January 13, 1997, requests expressing concern about the significant
      ongoing expenses incurred by the federal government to support the
      electricity-related activities of the power marketing administrations (PMAs)1
      and the Rural Utilities Service (RUS). The report also responds to your
      concerns regarding potential future losses from these activities, as well as
      those of the Tennessee Valley Authority (TVA), given the move toward
      deregulation and increased competition in the electricity industry.
      Accordingly, this report estimates the federal government’s net recurring
      cost2 from the electricity-related activities at the Department of
      Agriculture’s RUS, the Department of Energy’s PMAs, and TVA for fiscal year
      1996 and, where possible, the cumulative net cost for fiscal years 1992
      through 1996 (in constant 1996 dollars).3 As agreed with your offices, we
      estimated the net cost to the federal government on the accrual4 basis of
      accounting. These net costs already have had or will have an impact on the
      federal budget.


      1
       In this report, we discuss four of the five PMAs: Bonneville Power Administration (BPA),
      Southeastern Power Administration (Southeastern), Southwestern Power Administration
      (Southwestern), and Western Area Power Administration (Western). Because BPA had more than
      twice the revenue of the other three PMAs combined in fiscal year 1995 and faces different operating
      risks, we frequently discuss BPA separately. The fifth PMA, the Alaska Power Administration, is
      excluded from our analysis because legislation has been enacted to sell it to nonfederal entities.
      2
       We define net recurring cost (“net cost”) as the difference between the total expenses the federal
      government incurs and the total revenue it receives from its electricity-related activities in a given
      year.
      3
       RUS provides loans and loan guarantees primarily to rural electric cooperatives that generate,
      transmit, and/or distribute wholesale and retail power, the PMAs market wholesale power, and TVA
      generates and transmits wholesale power.
      4
       Accrual basis accounting recognizes the impact of revenue and expense transactions on the financial
      statements in the time periods when they occur, rather than when they result in cash receipts or
      disbursements.



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You also asked that we assess the likelihood of future losses beyond the
net recurring costs to the federal government from these entities. Based on
risk criteria similar to those used by major bond rating agencies, we
determined whether the likelihood of future losses to the federal
government from its direct and indirect involvement in the
electricity-related activities of RUS, the PMAs, and TVA was (1) remote,
(2) reasonably possible, or (3) probable, as defined in federal accounting
standards.5

The net costs and exposure to future financial losses result from the
federal government’s direct and indirect financial involvement in the
electricity-related activities of these entities. For this report, we defined
direct involvement as loans or loan guarantees made by the federal
government directly to RUS borrowers, the PMAs, and TVA, and appropriated
debt6 owed by the PMAs and TVA. As of September 30, 1996, the federal
government had over $53 billion of direct financial involvement in
electricity-related activities. The federal government would have financial
losses from its direct involvement if the RUS borrowers or the federal entity
were unable to repay debt owed to or explicitly guaranteed by the federal
government.

As of September 30, 1996, the federal government had indirect financial
involvement of over $31 billion—primarily BPA’s nonfederal debt7 and
bonds issued by TVA. Although BPA’s nonfederal debt and the 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 financial losses from its indirect
involvement if it incurred unreimbursed costs as a result of actions it took
to prevent default or breach of contract by the federal entity on nonfederal
debt.



5
 Statement of Federal Financial Accounting Standards No. 5, Accounting for Liabilities of the Federal
Government (SFFAS No. 5), indicates that if the chance that a contingent loss will occur is more likely
than not, then the loss is considered probable; if the chance of loss is more than remote but less than
probable, then the loss is considered reasonably possible; and if the chance of the loss occurring is
slight, then the loss is considered remote.
6
 We use the term “appropriated debt” because PMAs and TVA are required to repay appropriations
used for capital investments, with interest. However, these reimbursable appropriations are not
technically considered lending by the Department of the Treasury.
7
 BPA refers to this as “nonfederal project debt.” BPA used its contracting authority to acquire all or
part of the generating capability of power projects of 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 of volume 2 for additional discussion.



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                   Deregulation of the electricity industry has led to wholesale (sales for
                   resale) competition, which, combined with factors such as surplus power
                   and reduced production costs for gas-fired generation, has caused
                   wholesale electricity prices to fall in many parts of the country. The
                   increasingly competitive wholesale market and the financial vulnerability
                   of the RUS borrowers, the PMAs, and TVA have increased, in varying degrees,
                   the risk of future losses the federal government faces. Retail competition
                   is also expected to have a future impact on the electricity industry.
                   However, it is uncertain whether this will increase or decrease the
                   likelihood of future losses related to the federal government’s involvement
                   in electricity-related activities.

                   The overall results of our review are summarized in volume 1 of this
                   report. Volume 2 contains additional background information; details of
                   our objectives, scope, and methodology; additional details on our risk
                   analyses and the entities’ net cost to the federal government; written
                   agency comments, and major contributors to this report.


                   The federal government incurs net costs of over a billion dollars annually
Results in Brief   in supporting the electricity-related activities of RUS and the PMAs.
                   Additionally, the financial difficulties faced by RUS borrowers, BPA, TVA, and
                   one or a few projects at each of the three PMAs result in risk to the federal
                   government of future losses from these entities. The risk of loss from
                   these entities is heightened by the onset of competition in the electricity
                   industry.

                   The federal government is incurring substantial net costs annually from
                   the electricity-related activities of RUS and the PMAs, but generally does not
                   incur similar net costs from TVA. Although the PMAs are generally required
                   to recover all costs, favorable financing terms and the lack of specific
                   requirements to recover certain costs have resulted in net costs to the
                   federal government. Because RUS, on the other hand, is not legislatively
                   required or intended to recover all of its financing or other costs, interest
                   charges to its borrowers cover only a portion of the federal government’s
                   cost for that program. Additionally, RUS has recently experienced loan
                   write-offs.

                   We estimate that the net costs to the federal government for fiscal year
                   1996 totaled about $2.5 billion—$0.4 billion for BPA, $0.2 billion for the
                   three PMAs, and about $1.9 billion for RUS, including about $982 million in
                   RUS loan write-offs. Cumulatively, for fiscal years 1992 through 1996, we




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estimate that the government’s net cost of operating these entities has
been about $8.6 billion in constant 1996 dollars, including over $1 billion in
RUS loan write-offs. Under current operating policies and law, the federal
government will likely continue to incur many of the same types of costs.
However, for RUS, future loan write-offs cannot be accurately predicted. It
is important to note that these entities were generally following applicable
laws and regulations regarding recovery of costs.

The federal government is exposed to additional future losses beyond the
recurring net costs resulting from the government’s more than $84 billion
in direct and indirect financial involvement in the electricity-related
activities of RUS, the PMAs, and TVA as of September 30, 1996. These
potential future losses relate to the possibility that RUS borrowers, the
PMAs, or TVA would be unable to repay the full $53 billion in debt owed to
the federal government or that the federal government would incur
unreimbursed costs as a result of actions it took to prevent default or
breach of contract on the $31 billion in nonfederal debt.

This risk exists because certain RUS borrowers, the PMAs (to varying
degrees), and TVA are financially vulnerable primarily as a result of
uneconomical construction projects and the accumulation of substantial
debt, which have resulted in high fixed costs. For example, in fiscal year
1996, RUS wrote off almost $1 billion in loans to a borrower that incurred
significant debt as a minority-share owner of an uneconomical nuclear
plant. It is probable that the federal government will continue to incur
substantial losses from loan write-offs relating to RUS borrowers that are
currently classified by RUS as “financially stressed.”8 It is also probable that
future losses will arise from other RUS borrowers with high costs who are
unable to raise rates because of regulatory and/or market constraints.

Southeastern, Southwestern, and Western (referred to in this report as the
three PMAs) generally market wholesale power that consistently costs at
least 40 percent less than power sold by nonfederal utilities and are
therefore currently competitively sound overall. However, the three PMAs
maintain this overall soundness in part because they do not recover all
power-related costs. If they were required to recover some or all of these
power-related costs, which we estimate totaled about $0.2 billion for fiscal
year 1996, their ability to remain competitive might be impaired and the
risk of future financial loss to the federal government increased. Also,
each has one or a few projects or rate-setting systems with problems that,

8
 Borrowers classified by RUS as financially stressed have defaulted on their loans, had their loans
restructured but are still experiencing financial difficulty, declared bankruptcy, or have formally
requested financial assistance from RUS.



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             taken as a whole, make the risk of some loss to the federal government
             probable.

             For BPA, customer contracts, a memorandum of agreement limiting fish
             mitigation costs,9 and high current financial reserves10 make the risk of
             any significant loss to the federal government remote through fiscal year
             2001. However, the expiration of nearly all customer contracts, market
             uncertainties, high fixed costs, and substantial upward pressure on
             operating expenses make it reasonably possible that the federal
             government will incur some losses after fiscal year 2001 from BPA. This
             risk will begin to decline after 2012, all else being equal, if BPA pays off its
             nonfederal debt as scheduled.

             For TVA, the risk that the federal government will incur losses is remote as
             long as TVA retains a position similar to a traditional regulated utility
             monopoly11 in its service area. However, if this position changes and TVA is
             required to compete when wholesale prices are expected to fall, its high
             level of fixed costs and deferred assets compared to neighboring utilities
             make it reasonably possible that the federal government would incur
             future financial losses.


             Historically, electric utilities operated as regulated monopolies and were
Background   thus required to provide electricity service to all customers within their
             power service areas in exchange for exclusive service territories. Two key
             laws—the Public Utilities Regulatory Policies Act of 1978 (PURPA) and the
             Energy Policy Act of 1992—have resulted in an increasingly competitive
             wholesale electricity market. PURPA authorized operation of electric
             power-generating entities that were exempt from many federal
             regulations. Called “independent power producers” (IPPs),12 these entities
             typically use new technologies, such as natural gas-fired generation units,

             9
              These costs are incurred by BPA to protect and enhance fish and wildlife affected by federal hydro
             systems.
             10
              BPA’s financial reserves consist of cash and deferred federal borrowing authority. At the end of fiscal
             year 1996, BPA had a $278 million cash and deferred federal borrowing authority balance. In addition,
             credits from a $325 million contingency fund are available to BPA to fund fish-related costs incurred
             under specified circumstances.
             11
               Regulated monopolies are permitted by the government when unregulated market forces (e.g.,
             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.
             12
              IPPs, which are firms that produce electric power to be sold at wholesale rates, are not considered
             utilities because they do not produce power for a service area and do not engage in transmitting or
             distributing power.



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    to produce power. The Energy Policy Act of 1992 required that a utility
    make its transmission lines accessible to other utilities (called “open
    transmission access”). This open access has enabled wholesale customers
    to obtain electricity from a variety of competing suppliers, even if that
    power must be transmitted over lines owned by another utility—referred
    to as the “wheeling” of power. This ability to wheel power has resulted in
    increasing wholesale competition in the electricity industry across the
    United States, with competition becoming intense in some areas. As a
    result, wholesale electricity rates have decreased in many parts of the
    country over the last several years, which has impacted, to varying
    degrees, the PMAs, TVA, and RUS borrowers. On a retail basis, the traditional
    regulated utility monopoly still exists in most states. However, issues
    relating to retail open access are being addressed on a state-by-state basis
    and in the Congress, with end-use customer choice expected to result.

    Electricity generation, transmission, and distribution in the United States
    involves several government entities, including the following:

•   RUS, an entity within the Department of Agriculture (USDA), provides direct
    or guaranteed loans primarily to rural electric cooperatives that market
    power on a wholesale and retail basis.
•   Federal PMAs within the Department of Energy (DOE) market wholesale
    power generated primarily at federal water projects.
•   The U.S. Army Corps of Engineers (Corps) in the Department of Defense
    and the Bureau of Reclamation (Bureau) in the Department of the Interior
    both operate multipurpose water projects, many of which generate
    electric power. Other multipurpose project purposes include flood control,
    navigation, irrigation, and recreation. The Corps and Bureau allocate
    power-related costs and some irrigation and other nonpower costs for
    repayment through the PMAs’ power revenues. The Corps and the Bureau
    are referred to as the operating agencies.
•   TVA, a multipurpose, independent government corporation generates and
    transmits electricity, primarily on a wholesale basis, to distributors.

    To some extent, these entities interact with each other in the electricity
    market. For example, the PMAs sell power to some rural electric
    cooperatives financed by RUS, and Southeastern sells power to TVA. TVA
    also sells power to rural electric cooperatives. In aggregate terms, federal
    power generation represents about 10 percent, and rural electric
    cooperative generation represents about 4 percent, of all generating
    capability in the United States.




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                       In this report, we focus our discussions on the PMAs rather than the
                       operating agencies. This is because the PMAs are responsible for marketing
                       power produced at federal facilities and setting rates to recover the federal
                       government’s costs associated with the power production.

                       For a more detailed discussion of competition in the electricity market and
                       the federal entities involved, see appendix I in volume 2 of this report.


                       For fiscal year 1996, we estimate that the federal government incurred $2.5
RUS and PMA            billion in net costs, including about $982 million in RUS loan write-offs,13
Activities Result in   from the electricity-related activities of RUS and the PMAs. We estimate that
Recurring Net Costs    cumulative net costs for fiscal years 1992 through 1996 were about
                       $8.6 billion in constant 1996 dollars. Currently, the revenues earned by
to the Federal         these entities do not cover the full cost of their operations. As a result, the
Government             federal government rather than RUS borrowers and PMA ratepayers bears
                       these costs. TVA generally recovers all power-related costs from its
                       ratepayers.

                       To define the full cost to the PMAs and TVA of generating, transmitting,
                       and/or marketing federal power and to RUS of providing loans and loan
                       guarantees to its electricity borrowers, we referred to Office of
                       Management and Budget (OMB) Circular A-25, User Fees, industry practice
                       and federal accounting standards. Applying the definitions used in these
                       contexts, the full cost of generating, transmitting, and marketing power or
                       providing loans and loan guarantees would include all direct and indirect
                       costs incurred by RUS, the PMAs, TVA, and other entities directly involved in
                       supporting RUS, PMA, and TVA operations.

                       We estimated cumulative net costs for fiscal years 1992 through 1996
                       because information for these years was readily available. These
                       cumulative net cost calculations as well as those for fiscal year 1996 were
                       intended to measure the net cost to the federal government, on an accrual
                       basis, of the electricity-related activities of RUS, the PMAs, and TVA. It is
                       important to note that RUS, the PMAs, and TVA were generally following
                       applicable laws and regulations regarding recovery of costs.

                       Table 1 summarizes the net costs by type for each entity for fiscal year
                       1996 and cumulatively for the 5 years ending with fiscal year 1996 (in



                       13
                        Loan write-offs are considered to be a typical part of lending operations. However, RUS has not
                       experienced loan write-offs on a regular basis.



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                                          constant 1996 dollars). Each of the listed costs is discussed in detail
                                          following the table.


Table 1: The Federal Government’s Estimated Net Costs for Fiscal Year 1996 and Cumulatively for Fiscal Years 1992
Through 1996 for RUS, the Three PMAs, BPA, and TVA
Dollars in millions
                                                                                                                               Total
                                 RUS                    3 PMAs                    BPA                     TVA                            1992-
Net Cost                     1996    1992-96a        1996       1992-96a    1996     1992-96a       1996        1992-96a    1996         1996a
Financing                    $874      $3,812        $208        $1,155     $377        $1,974                             $1,459        $6,941
Loan write-offs               982       1,049                                                                                982          1,049
        b
Benefits                         1             3       16            82        21          110         $1            $4       39           199
Construction                                           30           138                       1                               30           139
                                                            c
Other                          21        112           (69)         157                                                       (48)         269
Total                      $1,878      $4,976        $185d       $1,532d    $398        $2,085         $1            $4    $2,462        $8,597
                                          Notes: Numbers may not add due to rounding. See appendix IV of volume 2 for a specific
                                          breakdown of net costs among the three PMAs and a discussion of the components of other net
                                          costs. Also, see appendix V of volume 2 for additional discussion of RUS’ net financing cost.
                                          a
                                           Cumulative net costs for fiscal years 1992 through 1996 are shown in constant 1996 dollars.
                                          b
                                              Benefits refers to pensions and postretirement health benefits.
                                          c
                                           This negative number results from Western’s fiscal year 1996 repayments of interest and
                                          operations and maintenance (O&M) expenses, which had been deferred in prior years.
                                          d
                                           About 23 percent of the fiscal year 1996 net costs and 9 percent of the cumulative net costs are
                                          potentially recoverable through future PMA rate charges.

                                          Source: GAO estimates based on entity annual reports and other data.




Rural Utilities Service
Net Financing Cost                        A net financing cost to the federal government exists in the RUS electric
                                          program because the annual interest income received from RUS borrowers
                                          is substantially less than the federal government’s annual interest expense
                                          on funds provided to the borrowers. Interest income is affected by
                                          favorable rates and terms given to some borrowers and also by financially
                                          troubled RUS borrowers that 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




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                  Transmission Cooperatives (G&T) borrowers.14 We estimate that the net
                  financing cost (interest expense minus interest income) to the federal
                  government for the RUS electric program for fiscal year 1996 was 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).15

                  Financially stressed borrowers’ failure to make scheduled payments has
                  had a significant impact on the federal government’s 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, the federal
                  government has forgone interest income of about $30 million per month,
                  or about $1 million per day, since December 1994. In the meantime, the
                  federal government continues to incur interest expense on financing
                  related to this borrower. A detailed discussion of the net financing costs
                  related to RUS is presented in appendix V of volume 2.

Loan Write-offs   RUS has recently written off, under Department of Justice (DOJ) authority, a
                  substantial dollar amount of loans to rural electric cooperatives. The most
                  significant loan write-offs are related to two G&T borrowers. In fiscal year
                  1996, about $982 million of one G&T borrower’s loans was written off and
                  forgiven because the G&T was unable to sell its electricity at a price
                  sufficient to service its RUS loans due to an investment in an uneconomical
                  nuclear plant. In the early part of fiscal year 1997, loans to another G&T
                  borrower were written off and forgiven for a loss of about $502 million
                  because the borrower was unable to recover costs for a coal-fired
                  generating plant built to satisfy anticipated demand that did not
                  materialize. The total amount of write-offs during fiscal years 1992 through
                  1996 was about $1.05 billion (in constant 1996 dollars)—with $0.5 billion
                  of additional write-offs in the early part of fiscal year 1997.16




                  14
                    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 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 between the two is that RUS management includes
                  borrowers that have officially requested financial assistance.
                  15
                    As these net financing costs reflect net interest expense incurred by Treasury in providing the
                  funding for RUS electricity loans, they do not correspond to RUS’ appropriations for those years.
                  16
                    According to RUS officials, as these amounts were forgiven, the borrowers were relieved of their
                  legal obligations; therefore, the federal government will make no further attempts to recover any of
                  these funds.


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Pension and Postretirement      The federal government also incurs costs for the electricity-related portion
Health Benefits and Other Net   of RUS’ appropriation for administrative expenses and for RUS employee
Costs                           pension and postretirement health benefits. In addition, attorneys at DOJ
                                spend substantial amounts of time litigating on behalf of RUS during loan
                                restructuring or bankruptcy proceedings. These estimated net costs
                                amounted to $1 million for benefits and $22 million in other charges for
                                fiscal year 1996 and $3 million and $112 million, respectively, for fiscal
                                years 1992 through 1996 (in constant 1996 dollars). These other net costs
                                are discussed in appendix IV of volume 2 to this report.


Power Marketing
Administrations
Net Financing Cost              The net financing cost for the PMAs results primarily from appropriated
                                debt provided by the federal government at low interest rates with
                                favorable repayment terms. Appropriated debt carries a fixed interest rate
                                with no ability for Treasury to call17 the debt. Although PMAs are generally
                                required18 to pay off highest interest rate debt first, they cannot refinance
                                the debt. Thus, Treasury bears the risk of increases in interest rates and
                                PMAs, to some degree, bear the risk of decreases in interest rates. The
                                interest rates on outstanding PMA appropriated debt are substantially
                                below the rates Treasury incurs to provide funding to the PMAs and other
                                federal programs. Thus, interest income earned by Treasury on the
                                appropriated debt is less than Treasury’s interest expense, which it incurs
                                to finance this debt. The PMAs have accumulated substantial amounts of
                                appropriated debt at low interest rates primarily because, in accordance
                                with applicable guidance, they repay high interest rate debt first and
                                because PMA appropriated debt incurred prior to 198319 was generally at
                                below-market interest rates in effect at the time. We estimate that the net
                                financing cost for the three PMAs’ appropriated debt for fiscal year 1996
                                was $208 million and for BPA, $377 million. Cumulatively, for fiscal years
                                1992 through 1996, we estimate that the net financing cost in constant 1996
                                dollars has been over $1.1 billion for the three PMAs and nearly $2 billion

                                17
                                 The term “call” refers to the legal right of the lender to require the borrower to pay back the debt
                                before its maturity date.
                                18
                                 DOE order RA6120.2, “Power Marketing Administration Financial Reporting,” generally requires the
                                PMAs to repay the highest interest rate debt first, while still complying with repayment periods and
                                unless otherwise indicated by legislation.
                                19
                                  In 1983, DOE required that in the absence of specific legislation to the contrary, appropriations for
                                capital expenditures made after September 30, 1983, be financed at interest rates equal to the average
                                yield during the preceding fiscal year on interest-bearing marketable securities of the United States,
                                which, at the time the computation is made, have terms of 15 years or more remaining to maturity.



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                                          for BPA. Table 2 shows the differences in the interest rates paid by the
                                          PMAs, Treasury’s cost of funds, and the components of our estimates.



Table 2: Estimated PMA Net Financing Costs for Fiscal Year 1996 and Cumulatively for Fiscal Years 1992 Through 1996
Dollars in millions
                                   Outstanding
                                  appropriated
                                    debt as of Weighted average              Treasury average        Fiscal year 1996            Fiscal years
                                 September 30,      interest rate                 interest rate         net financing           1992-1996 net
PMA                                      1996a         (percent)a                   (percent)b                  costs        financing costsc
Southeastern                             $1,491                        4.4                   9.0                     $68                     $363
Southwestern                                   686                     2.9                   9.0                      42                        244
Western                                   3,217                        6.0                   9.0                      98                        548
  Total—Three PMAs                       $5,394                                                                    $208                  $1,155
BPA                                      $6,848                        3.5                   9.0                   $377                  $1,974
                                          Note: For a discussion of our methodology for the above calculations, see appendix II of
                                          volume 2.
                                          a
                                           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, the appropriated debt balances did not change
                                          significantly in fiscal year 1996. We then calculated the fiscal year 1996 net financing cost using
                                          the 1996 Treasury average interest rate.
                                          b
                                           This rate represents the weighted average interest rate on Treasury’s entire outstanding bond
                                          portfolio (10- to 30-year maturities). We used this interest rate because it reflects Treasury’s
                                          average interest rate on outstanding long-term debt and most closely matches the terms of the
                                          PMAs’ appropriated debt.
                                          c
                                           In constant 1996 dollars.

                                          Source: GAO estimates based on PMA annual reports and information from the Bureau of the
                                          Public Debt, Department of the Treasury.



                                          As a result of legislation passed in 1996,20 BPA’s appropriated debt was
                                          restructured from $6.85 billion, with an average interest rate of 3.5
                                          percent, to $4.29 billion, with an average interest rate of 7.1 percent.
                                          According to BPA’s 1996 final rate proposal, the restructuring “is intended
                                          to permanently eliminate subsidy criticisms directed at the relatively low
                                          interest rates assigned to historic Federal Columbia River Power System
                                          (FCRPS)21 appropriations.”



                                          20
                                           The Omnibus Consolidated Rescissions and Appropriations Act of 1996 (Public Law 104-134, April 26,
                                          1996, 110 Stat. 1321-350) called for a “refinancing” of BPA’s appropriated debt.
                                          21
                                           BPA is part of 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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                             The legislation required that the present value of the new principal balance
                             equal the present value of the principal and interest payments that would
                             have been made if restructuring had not occurred, plus an additional
                             $100 million. The legislation also required that the interest rate applicable
                             to the new principal balance (including the additional $100 million) be set
                             to approximate the prevailing interest rate on Treasury debt of
                             comparable maturity issued at the time of the restructuring. The dates at
                             which the segments of appropriated debt become due are not changed by
                             the legislation. As was the case before the restructuring, the due dates
                             extend through the year 2046 and average about 26 years remaining.

                             Because the restructuring was not effective for fiscal year 1996, this
                             transaction did not change the $377 million estimated net financing cost
                             on BPA appropriated debt for fiscal year 1996. In the future, with the
                             exception of the $100 million, if BPA repays appropriated debt at maturity,
                             the net present value of future financing costs to the federal government
                             will also remain unchanged.22

                             BPA  also 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 set based on debt
                             with similar terms issued by U.S. government corporations. This debt
                             matures in fiscal years 1997 through 2034, with $346.2 million maturing by
                             the year 2000. Based on our review of the terms of this debt, we believe
                             there is no net cost to the federal government.

Pension and Postretirement   The federal government incurs a portion of the cost for Civil Service
Health Benefits              Retirement System (CSRS) pensions and substantially all of the cost for
                             postretirement health benefits for current23 PMA and operating agency
                             employees. For fiscal year 1996, we estimate that the net cost to the
                             federal government of providing these benefits was about $16 million for
                             the three PMAs and almost $21 million for BPA. Cumulatively, for fiscal
                             years 1992 through 1996, we estimate that the net cost in constant 1996
                             dollars was $82 million for the three PMAs and $110 million for BPA.

                             Recovery of the full annual cost of pension and postretirement health
                             benefits is planned by Southeastern, Southwestern, and Western starting
                             in fiscal year 1998. BPA plans to begin recovering some of these costs in


                             22
                              However, if BPA repays 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 resultant increase in
                             net cost.
                             23
                              We did not calculate the cost of benefits provided to retired employees because the information was
                             not available from the Office of Personnel Management (OPM).



                             Page 12                                           GAO/AIMD-97-110 Federal Electricity Activities
                     B-276640




                     1998, with full recovery planned beginning in 2002. Consistent with current
                     policies and law, the PMAs do not plan to recover pre-fiscal year 1998 net
                     costs.

Construction Costs   We found that all of the PMAs had incurred costs and/or had costs allocated
                     to them by the operating agencies for projects that were completed, under
                     construction, or cancelled, for which the full costs were not being
                     recovered. In some cases, this was because the power-generating projects
                     had never operated as designed. In accordance with DOE guidance, the
                     PMAs set rates that exclude the costs of nonoperational parts of power
                     projects, including capitalized interest. For example, at the Russell
                     Project, partially on line since 1985, litigation over excessive fish kills has
                     kept four of the eight turbines from becoming operational. As a result,
                     over one-half of the project’s construction costs—about
                     $500 million—have been excluded from Southeastern’s rates.

                     The net costs relating to these construction projects for fiscal year 1996
                     represent capitalized or unpaid interest incurred in that year. We estimate
                     that for fiscal year 1996, the net cost to the federal government for the
                     projects we identified is $30 million for the three PMAs and $0.2 million for
                     BPA. Cumulatively, from fiscal years 1992 through 1996, we estimate that
                     the net cost in constant 1996 dollars is about $138 million for the three
                     PMAs and $1.2 million for BPA.24 The PMAs have stated that in most of these
                     instances, including Russell, these net costs will be recovered in future
                     years.

Other                The PMAs incur a number of other net costs including environmental
                     mitigation, irrigation, deferred payments, and interest expense on store
                     supplies totaling approximately $157 million cumulatively for fiscal years
                     1992 through 1996 in constant 1996 dollars. A net recovery totaling
                     approximately $69 million existed for fiscal year 1996 resulting from
                     Western’s repayments of interest and O&M expenses which had been
                     deferred in prior years. These other net costs are discussed in appendix IV
                     of volume 2 of this report.




                     24
                       These amounts do not include the actual construction and capitalized interest costs that were
                     incurred prior to fiscal year 1992. These costs are further discussed in appendix VII of volume 2 in
                     connection with our risk assessment of the three PMAs.



                     Page 13                                            GAO/AIMD-97-110 Federal Electricity Activities
                                B-276640




Tennessee Valley Authority
TVA’s Federal Financing         Unlike the PMAs’ appropriated debt, TVA’s appropriated debt has terms that
Results in No Net Cost to the   provide Treasury full reimbursement for its related financing costs.
Federal Government              Substantially all of TVA’s appropriated debt was incurred prior to the 1959
                                self-financing amendments to the TVA Act. The Tennessee Valley Authority
                                Act of 1933, as amended, requires TVA to make fixed annual payments of
                                principal to Treasury and pay interest at an annually calculated Treasury
                                interest rate on the outstanding balance. In accordance with the TVA Act,
                                the interest rate is what Treasury pays on its total marketable public
                                obligations issued—6.87 percent for fiscal year 1996.25 The terms of this
                                debt include resetting of the interest rate annually, which is a short-term
                                debt feature, and a principal repayment term of over 50 years, which is
                                characteristic of long-term debt. Consequently, we believe that the terms
                                of this debt, including the use of Treasury’s total average interest rate for
                                all debt, result in no net cost to the federal government.

                                As of September 30, 1996, TVA also had $3.2 billion of long-term debt that
                                was held by the Federal Financing Bank (FFB).26 This debt matures at
                                various dates from fiscal years 2003 through 2016 and bears interest rates
                                ranging from about 8.5 percent to 11.7 percent. Because the interest rate
                                on TVA’s FFB debt is based on the rate Treasury pays plus a one-eighth of
                                1 percent administrative fee, we believe there was no net financing cost to
                                the federal government for this debt in fiscal years 1992 through 1996.

                                Recently, TVA asked the 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




                                25
                                 Total marketable obligations include all outstanding short-term and long-term marketable Treasury
                                securities, including Treasury bills, notes, bonds, and Federal Financing Bank securities.
                                26
                                  TVA’s FFB debt was issued from fiscal years 1985 through 1989 with terms ranging from 14 to 30
                                years. Interest rates ranged from 11.7 percent for the 30-year bonds issued in 1985 to 8.5 percent for
                                16-year bonds issued in 1988. These bonds do not have any call provisions, but TVA has the option of
                                repurchasing the FFB bonds under standard FFB repayment provisions. FFB obtains the funds
                                provided to TVA by borrowing from the Department of the Treasury. FFB charges TVA the interest it
                                incurs on its Treasury borrowing, plus a fee of at least one-eighth of 1 percent to cover administrative
                                costs.



                                Page 14                                            GAO/AIMD-97-110 Federal Electricity Activities
                             B-276640




                             in loans made by the FFB without paying the prepayment premiums.27 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. The
                             estimated cost reflects the net effect of the refinancing on both Treasury
                             and TVA. This proposed legislation was never introduced.

Pension and Postretirement   TVA has its own pension and postretirement health benefit plans, which are
Health Benefits              funded through TVA’s electricity rate charges. TVA’s postretirement health
                             plan covers all TVA employees while its pension plan covers all employees
                             except for a small number covered by federal plans. As of September 30,
                             1996, TVA had about 163 staff employed in its power program that were
                             part of the federal government’s pension plans.28 As with most other
                             federal agencies, TVA does not currently reimburse the federal government
                             for the full cost of the benefits of employees covered by the CSRS. We
                             estimate that the net cost to the federal government for these benefits was
                             about $0.7 million in fiscal year 1996 and about $4 million for fiscal years
                             1992 through 1996 in constant 1996 dollars.


                             The federal government has financial exposure stemming from its over
Federal Government           $84 billion of direct and indirect financial involvement in the
Faces Risk of Future         electricity-related activities of RUS, the PMAs, and TVA. Comparatively high
Losses Due to                debt and fixed costs resulting from factors such as investments in
                             uneconomical construction projects have left federal electricity-related
Financial                    entities vulnerable, in varying degrees, and results in risk of future losses
Vulnerability of             to the federal government. The federal government’s risk of future losses
                             is directly related to the ability of the RUS borrowers, the PMAs, and TVA to
Electricity-Related          set their rates in a competitive and/or regulated market at a level sufficient
Entities                     to recover all of their costs.




                             27
                              The prepayment premium is charged by FFB in order to protect FFB from incurring an economic loss
                             on the prepayment. This premium is calculated based on the difference between the book (face) value
                             and Treasury’s 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.
                             28
                               These employees transferred to TVA from other federal agencies. Under OPM’s implementation of
                             the Civil Service Retirement Act, federal employees who transfer from one federal entity to another,
                             including TVA, have the right to retain their federal pension benefits if there has not been a break in
                             service of more than 3 days. TVA employees are not covered by the same postretirement health
                             benefits plan as other federal employees.



                             Page 15                                            GAO/AIMD-97-110 Federal Electricity Activities
                                       B-276640




Federal Government Has                 The federal government faces financial exposure because of direct and
Substantial Financial                  indirect financial involvement in the electricity-related activities of RUS, the
                                       PMAs, and TVA. As of September 30, 1996, the federal government had over
Involvement in
                                       $53 billion of primarily direct lending to RUS borrowers, the PMAs, and TVA
Electricity-Related                    and appropriated debt owed by the PMAs and TVA. The federal government
Activities                             would incur a future loss on this direct involvement to the extent that RUS
                                       borrowers, the PMAs, or TVA failed to make payments on federal debt.

                                       As of September 30, 1996, the federal government also had indirect
                                       financial involvement of over $31 billion—primarily TVA bonds and BPA’s
                                       nonfederal debt. Although the TVA bonds and BPA’s nonfederal debt are not
                                       explicitly guaranteed by the federal government, the financial community
                                       generally views them as having an implicit federal guarantee. For this
                                       indirect involvement, the federal government would incur future losses if
                                       it incurred unreimbursed costs as a result of actions it took to prevent
                                       default or breach of contract by the federal entity on nonfederal debt.
                                       Table 3 shows the federal government’s direct and indirect financial
                                       involvement in RUS, the three PMAs, BPA, and TVA.

Table 3: The Federal Government’s
Financial Involvement in               Dollars in billions
Electricity-Related Activities as of                                                               Financial involvementa
September 30, 1996
                                       Entity                                                 Direct             Indirect                Total
                                       RUS                                                     $32.3                                     $32.3
                                       Three PMAs                                                 7.0                $0.2b                $7.2
                                                                                                                          c
                                       BPA                                                      10.1                   7.1               $17.2
                                       TVA                                                        3.8                24.1                $27.9
                                       Total                                                   $53.2                $31.4                $84.6
                                       Note: See appendixes VI through IX in volume 2 for a detailed discussion of the components of
                                       the financial involvement for each entity.
                                       a
                                        Financial involvement represents these entities’ total outstanding debt for which the federal
                                       government is either directly or indirectly at risk. The federal government could sell the
                                       power-related assets of RUS’ borrowers, the PMAs, and TVA to offset some or all of any actual
                                       losses the federal government incurred as a result of its financial involvement with these entities.
                                       b
                                        For the three PMAs, indirect involvement refers to capital provided by Western’s customers
                                       (primarily through the issuance of bonds) to finance capital improvement projects (nonfederal
                                       debt). The customers pay the debt service cost, and Western records the proceeds as a liability
                                       and records interest expense. Western then bills the customers for the production costs of
                                       electricity, including the debt service, and credits the customers for the debt service costs.
                                       Essentially, this arrangement results in customers directly paying for capital improvements rather
                                       than paying for them indirectly through rates.
                                       c
                                        For BPA, indirect involvement refers primarily to BPA’s nonfederal debt, which was previously
                                       noted.

                                       Source: GAO analysis of information contained in entity annual reports and other data.




                                       Page 16                                           GAO/AIMD-97-110 Federal Electricity Activities
                                 B-276640




Risk Hinges on Probability       In assessing risk to the federal government, we used the criteria for
of Loss                          contingencies from Statement of Federal Financial Accounting Standards
                                 (SFFAS) No. 5, Accounting for Liabilities of the Federal Government.
                                 According to SFFAS No. 5, “A contingency is an existing condition,
                                 situation, or set of circumstances involving uncertainty as to possible gain
                                 or loss to an entity. The uncertainty will ultimately be resolved when one
                                 or more future events occur or fail to occur.” When a loss contingency
                                 exists, the likelihood that the future event or events will confirm the loss
                                 or the incurrence of a liability can range from probable to remote:

                             •   Probable: The future confirming event or events are more likely than not to
                                 occur.
                             •   Reasonably possible: The chance of the future confirming event or events
                                 occurring is more than remote but less than probable.
                             •   Remote: The chance of the future event or events occurring is slight.

                                 We assessed risk of loss for RUS, which is essentially a lending operation,
                                 based on a review of the loan portfolio, an assessment of the production
                                 costs of key borrowers relative to their respective markets, and
                                 consideration of state regulatory actions. For the three PMAs, BPA, and TVA,
                                 we considered the cost of electricity production and rates, key financial
                                 ratios, generating mix, competitive environment, management actions, and
                                 legislative and other factors. The risk factors we used to assess risk of loss
                                 to the federal government from its electricity-related activities are
                                 consistent with those used by the bond rating services to assess credit risk
                                 for nonfederal utilities.29


Average Revenue Per              In a competitive market for a relatively homogeneous product like
Kilowatthour Is a Key            electricity, being among the lowest cost producers is generally the most
Determinant of                   important factor in determining competitive position. As discussed below,
                                 average revenue per kilowatthour (kWh) is a reasonable indicator of
Competitive Position             power production costs.30 Thus, because RUS borrowers and the PMAs are
                                 subject to some wholesale competition, one of the key factors we looked
                                 at in assessing the risk described in this section of the report was these
                                 entities’ average revenue per kWh for wholesale sales compared to
                                 nonfederal utilities. The average revenue per kilowatthour for wholesale


                                 29
                                   We consulted Fitch Investors Service, Inc., New York, New York, and Moody’s Investors Service,
                                 New York, New York, regarding the criteria they use to assess risk when preparing bond ratings for
                                 electric utilities.
                                 30
                                   This assumes that the entity’s competitive position is such that it can charge sufficiently high rates to
                                 recover all costs from customers.



                                 Page 17                                             GAO/AIMD-97-110 Federal Electricity Activities
                              B-276640




                              sales (sales for resale) is referred to in this report as average revenue per
                              kWh.

                              This average is calculated by dividing total revenue from the sale of
                              wholesale electricity by the total wholesale kWhs sold. Because the 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 PMAs’, POGs’, and rural electric cooperatives’ power
                              production costs. For investor-owned utilities (IOUs), average revenue per
                              kWh should reflect power production 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.


Continuing Losses From        During fiscal year 1996 through July 31, 1997, RUS has written off about
RUS Loan Portfolio Are        $1.5 billion in electricity loans. As of September 30, 1996, $10.5 billion of
Probable                      the $32.3 billion total electricity portfolio relates to loans to G&Ts that are
                              in bankruptcy or otherwise financially stressed. The total principal
                              outstanding on G&T loans is approximately $22.5 billion, or about
                              70 percent of the RUS electric loan portfolio. Distribution borrowers make
                              up the remaining 30 percent of the electric loan portfolio. At the time of
                              our review, there were 55 G&T borrowers and 782 distribution borrowers.
                              Our review focused on the G&T loans since they make up the majority of
                              the portfolio in terms of dollars and generally pose the greatest risk of loss
                              to the federal government. It is probable that the federal government will
                              continue to incur substantial losses on the loans to financially stressed G&T
                              borrowers. It is also probable that additional future losses will be incurred
                              on loans to G&T borrowers that are not currently troubled but will become
                              financially stressed due to high production costs and competitive and/or
                              regulatory pressures.

Substantial Loan Write-offs   Under DOJ authority, RUS has recently written off a substantial dollar
Occurred in Recent Years      amount of loans to rural electric cooperatives. The most significant
                              write-offs related to G&T loans. In fiscal year 1996, one G&T made a lump
                              sum payment of $237 million to RUS in exchange for RUS writing off and
                              forgiving the remaining $982 million of its RUS loan balance. This
                              borrower’s financial problems stemmed from its participation in a nuclear
                              plant construction project that experienced lengthy delays 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



                              Page 18                               GAO/AIMD-97-110 Federal Electricity Activities
                                B-276640




                                Congressional Research Service, the accrued expenditures by 1988 were
                                $3.9 billion as measured in nominal terms (1988 dollars). These cost
                                increases are due primarily to changes in Nuclear Regulatory Commission
                                (NRC) health and safety regulations after the Three Mile Island accident.
                                The remaining increases are generally due to inflation over time and
                                capitalization of interest during the delays.

                                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 total amount of debt
                                written off for the entire RUS electricity loan portfolio between fiscal years
                                1992 and 1996 was about $1.05 billion (in constant 1996 dollars)—with
                                $0.5 billion in additional write-offs in the early part of fiscal year 1997.

Additional Losses From          It is probable that RUS will have additional loan write-offs and therefore
Financially Stressed G&T        that the federal government will incur further losses in the short term from
Borrowers Are Probable in the   borrowers that RUS management has identified as financially stressed.
Short Term                      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. Of these, 4 borrowers
                                with about $7 billion in outstanding debt are in bankruptcy. The remaining
                                9 borrowers have investments in uneconomical generating plants and/or
                                have formally requested financial assistance in the form of debt
                                forgiveness from RUS. According to RUS officials, these plant investments
                                became uneconomical because of cost overruns, continuing changes in
                                regulations, and soaring interest rates. These investments resulted in high
                                levels of debt and debt-servicing requirements, making power produced
                                from these plants expensive.

                                Since cooperatives are nonprofit organizations, little or no profit is built
                                into their rate structure, which helps keep electricity rates as low as
                                possible. However, the lack of retained profits generally means the



                                Page 19                               GAO/AIMD-97-110 Federal Electricity Activities
                              B-276640




                              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, or default
                              on government loans.

                              This was the scenario for the previously discussed write-offs in fiscal year
                              1996 and through July 31, 1997. Additional write-offs are expected to
                              occur. For example, according to RUS officials, the agency may write off as
                              much as $3 billion of the total $4.2 billion debt owed by Cajun Electric, a
                              RUS borrower that has been in bankruptcy since December 1994. Cajun
                              Electric filed for bankruptcy protection after the Louisiana Public Service
                              Commission disapproved a requested rate increase and instead lowered
                              rates to a level that reduced the amount of revenues available to Cajun to
                              make annual debt service payments. Several factors contributed to Cajun’s
                              heavy debt, including its investment in a nuclear facility which
                              experienced construction cost overruns and its excess electricity
                              generation capacity resulting from overestimation of the demand for
                              electricity in Louisiana during the 1980s.

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

                              We believe the future viability of these G&T loans will be determined based
                              in part on the RUS cooperatives’ ability to be competitive in a deregulated
                              market. To assess the ability of RUS cooperatives to withstand competitive
                              pressures, we focused on the average revenue per kWh of 33 of the 55 G&T
                              borrowers with about $11.7 billion of loans outstanding as of
                              September 30, 1996. We excluded 9 G&Ts that only transmit electricity and
                              the 13 financially stressed borrowers. Our analysis shows that for 27 of the
                              33 G&T borrowers, average revenue per kWh was higher in their respective
                              regions than IOUs, and 17 of the 33 were higher than POGs. Additionally, as
                              shown in figure 1, in 1995, RUS cooperatives’ average revenue per kWh was
                              higher than IOUs in all of the eight primary North American Electric
                              Reliability Council (NERC) regions in which the cooperatives operate. 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



                              Page 20                              GAO/AIMD-97-110 Federal Electricity Activities
                                       B-276640




                                       costs. However, RUS officials stated that they will not write off debt solely
                                       to make borrowers more competitive.


Figure 1: Average Revenue per kWh
for Wholesale Power Sold in 1995 for
                                       5.0   Cents per kWh
RUS G&T Borrowers Compared to
IOUs in Their Regional Markets                                                               4.5
                                                                                                   4.4
                                                                     4.2
                                                                                                                     4.1
                                                         4.0
                                       4.0                     3.9                                                               3.9
                                             3.7
                                                                                                         3.5
                                                                                 3.2                                       3.2         3.2

                                       3.0
                                                   2.7                                                         2.7
                                                                           2.5
                                                                                       2.4


                                       2.0




                                       1.0




                                        0

                                                ECAR    ERCOT          MAIN        MAPP        SERC        SPP         WSCC        ASCC
                                                NERC Region



                                                         RUS G&Ts

                                                         IOUs



                                       Legend

                                       ECAR = East Central Area Reliability Coordination Agreement
                                       ERCOT = Electric Reliability Council of Texas
                                       MAIN = Mid-America Interconnected Network
                                       MAPP = Mid-Continent Area Power Pool
                                       SERC = Southeastern Electric Reliability Council
                                       SPP = Southwest Power Pool
                                       WSCC = Western Systems Coordinating Council
                                       ASCC = Alaska Systems Coordinating Council

                                       Note: We compared Alaskan cooperatives to POG data since IOU data were unavailable. See
                                       appendix III of volume 2 for a map of the above regional markets.

                                       Source: GAO analysis of data from the RUS fiscal year 1995 annual report, preliminary
                                       (unaudited) 1995 IOU data from the Energy Information Administration, and POG data from the
                                       American Public Power Association (APPA).




                                       Page 21                                                     GAO/AIMD-97-110 Federal Electricity Activities
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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, two unique
factors 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 general inability to refinance higher cost FFB debt when lower interest
rates have prevailed. However, RUS officials said that recent legislative
changes that enable cooperatives to refinance FFB debt with a penalty may
help align G&T interest rates with those of the IOUs.

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

Wholesale rates under these contracts are currently set by a G&T’s board of
directors with approval from RUS. In states whose commissions regulate
cooperatives, the cooperative 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.

As discussed above, denials of requested rate increases by state
commissions culminated in several G&Ts filing for bankruptcy. Eighteen of
the RUS G&T 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



Page 22                             GAO/AIMD-97-110 Federal Electricity Activities
                            B-276640




                            on the region. According to RUS officials, some commissions have denied a
                            rate increase to cover the costs of projects that the commission had
                            previously approved for construction. Therefore, G&Ts with high costs may
                            be likely candidates to default on their RUS loans, even without direct
                            competitive pressures.


Three PMAs Are              At September 30, 1996, the three PMAs had $5.4 billion of appropriated
Competitively Sound         debt, and Western had an additional $1.6 billion of irrigation debt31 and
Overall, but Risk of Loss   about $165 million of nonfederal debt. The three PMAs market power that is
                            substantially lower in cost than nonfederal utilities and thus, in the current
for Certain Projects Is     operating environment, are competitively sound overall. However, all
Probable                    three PMAs have one or a few projects or rate-setting systems with
                            problems that, taken as a whole, make risk of some loss to the federal
                            government probable.

                            As shown in figure 2, Southeastern, Southwestern, and Western have
                            production costs that average more than 40 percent below IOUs and POGs in
                            the primary NERC regions in which the PMAs operate.




                            31
                              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.



                            Page 23                                             GAO/AIMD-97-110 Federal Electricity Activities
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Figure 2: Average Revenue per kWh
for Wholesale Power Sold in 1995 for
                                       6   Cents per kWh
the Three PMAs Compared to IOUs
and POGs in Their Respective Regions
                                                         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



                                                          PMA

                                                          IOUs

                                                          POGs



                                       Legend

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

                                       Source: GAO analysis of data from the PMAs’ 1995 annual reports, preliminary (unaudited) 1995
                                       IOU data from EIA, and POG data from APPA.




                                       The three PMAs are low-cost marketers of power for several key reasons.
                                       First, the three PMAs market power produced primarily at hydropower
                                       dams built 30 to 60 years ago and run primarily by the operating agencies.
                                       These hydropower dams are currently a low cost energy source compared
                                       to coal and nuclear fuels, which are the primary energy sources used by
                                       other utilities.

                                       Another key advantage for the three PMAs is that as federal agencies, they
                                       generally do not pay taxes. In contrast, IOUs do pay taxes. According to the



                                       Page 24                                               GAO/AIMD-97-110 Federal Electricity Activities
                           B-276640




                           Energy Information Administration (EIA),32 IOUs paid taxes averaging about
                           14 percent of operating revenues in 1995. 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 study33 of 670 public distribution utilities showed
                           that the POGs’ median net payments and contributions as a percent of
                           electric operating revenue were 5.8 percent.

                           Finally, as previously mentioned, the three PMAs did not recover nearly
                           $185 million of costs in fiscal year 1996 associated with producing and
                           marketing federal power. If Congress were to require the three PMAs to
                           begin recovery of the net costs described earlier, or if competition drives
                           electricity prices down significantly, the three PMAs’ competitive position
                           could deteriorate.

                           Because the three PMAs market power at prices that are substantially
                           below those of other utilities, they generally have had little difficulty in
                           selling all of the power that they produce. However, as discussed in detail
                           in appendix VII of volume 2, each of the three PMAs has one or a few
                           projects or rate-setting systems with problems that, taken as a whole,
                           make the risk of some future losses to the federal government probable. In
                           aggregate, these problem projects and rate-setting systems represent
                           about $1.4 billion,34 or 19 percent of the federal government’s financial
                           involvement in the three PMAs.


Risk of Loss From BPA Is   BPA had over $17 billion of debt and over $766 million of interest expense
Remote Through Fiscal      as of and for the year ended September 30, 1996. These high fixed costs
Year 2001 but Increases    limited BPA’s flexibility to lower rates and contributed significantly to BPA’s
                           loss of customers in recent years. However, as a result of existing
Thereafter                 customer contracts, a memorandum of agreement (MOA) limiting fish
                           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 2001, expiration of customer contracts,
                           significant risks from market uncertainties, BPA’s high fixed costs, and
                           substantial upward pressure on operating expenses increase the risk of
                           loss to the federal government. Despite a number of factors that mitigate
                           this risk, we believe it is reasonably possible that the federal government

                           32
                             EIA is a statistical and analytical agency in the Department of Energy.
                           33
                            1994 Payments and Contributions by Public Power Distribution Systems to State and Local
                           Government, American Public Power Association, March 1996.
                           34
                            Of the problem projects, about $518 million relates to Southeastern, $839 million to Western, and
                           $31 million to Southwestern.


                           Page 25                                            GAO/AIMD-97-110 Federal Electricity Activities
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                              will incur losses from BPA after fiscal year 2001. This risk will begin to
                              decline after 2012, all else being equal, if BPA pays off its nonfederal debt as
                              scheduled. In addition, one small project that serves BPA represents a
                              probable loss to the federal government (see appendix VIII of volume 2).

Key Factors Stabilize BPA     Three key factors have stabilized the government’s risk of loss relative to
Through Fiscal Year 2001      BPA through fiscal year 2001 and, in our view, make risk remote for this
                              timeframe. First, in 1995-96, BPA signed its customers to contracts to
                              purchase a substantial amount of power through fiscal year 2001. BPA
                              projects that firm power sales to these customers will secure $1.14 billion
                              annually through fiscal year 2001, or 63 percent of each year’s total
                              projected power revenues. Second, BPA management entered into a MOA
                              with various federal agencies that has limited its fish mitigation costs
                              through fiscal year 2001. This agreement also created a contingency fund
                              of $325 million comprised of past BPA nonpower fish mitigation
                              expenditures.35 Finally, BPA has had strong water years in 1996 and so far
                              in 1997 and estimates that it will have financial reserves of about
                              $400 million at the end of fiscal year 1997.36 In addition, the $325 million
                              fish cost contingency fund is available under specified circumstances.

Risk Increases After Fiscal   After fiscal year 2001, BPA faces the expiration of customer contracts,
Year 2001                     significant market uncertainties, high fixed costs, and significant upward
                              pressure on operating expenses. Nearly all of BPA’s power contracts with
                              customers expire at the end of fiscal year 2001. If these customers can find
                              power cheaper than BPA can offer, they might opt to leave BPA. One of the
                              key market uncertainties that will determine whether cheaper power will
                              be available is the future 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 technology advances have

                              35
                                BPA is required by the Northwest Power Act to protect, mitigate, and enhance fish and wildlife
                              resources to the extent these resources are affected by federal hydroelectric projects. Section
                              4(h)(10)(C) of this act directs BPA to allocate fish and wildlife costs to the various project purposes,
                              for example, power, irrigation, and flood control. The reserve represents the portion of BPA’s
                              expenditures that are related to nonpower uses of the projects. It is important to note that to the
                              extent BPA uses the $325 million reserve, the federal government will incur these costs because the
                              MOA allows BPA to apply the $325 million, under specified circumstances, as a credit against BPA’s
                              Treasury payment.
                              36
                               BPA financial reserves of about $400 million include cash and deferred Treasury borrowing authority.
                              Deferred borrowing authority 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. The deferred Treasury borrowing authority is similar to an unused line of credit. While this
                              may be useful in the short term to provide liquidity, its use results in additional debt; thus, deferred
                              borrowing authority is not a long-term solution to financial difficulty.



                              Page 26                                            GAO/AIMD-97-110 Federal Electricity Activities
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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 leaving or obtaining
some of their power at rates well below BPA’s current rate.

According to BPA, a surplus of power on the west coast is also driving
down the price of wholesale power. Because utilities are still 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 marketers37 are offering wholesale power at as low as 1.5 cents per
kWh, which is lower than BPA’s price for sales of comparable products 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.

It is also uncertain what impact retail open access will have on BPA’s
competitive position. Retail open access—which would provide retail
consumers freedom to choose among suppliers—could result in BPA’s
wholesale customers being uncertain about the size of their own future
power needs. These power needs will be directly impacted by retail
customers being able to choose their supplier. BPA’s customers may be
hesitant to sign long-term contracts to purchase power from BPA to the
extent they face uncertainty about future power needs. However, even
without long-term contracts, BPA is likely to remain a major supplier. Most
states and the Congress are considering various proposals regarding the
approach to retail open access.

BPA’s substantial fixed costs will continue to inhibit its flexibility to lower
its rates and meet competitive pressures. For example, 32 percent of BPA’s
revenue went to pay financing costs in fiscal year 1996—substantially
more than the nationwide average of 14 percent for IOUs and 18 percent for
POGs. BPA will continue to face high fixed costs after fiscal year 2001
relating to its $17 billion of debt.

BPA will also face upward pressure on its operating expenses after fiscal
year 2001. The most significant of these operating expenses is fish
mitigation. It is uncertain whether an agreement similar to the current MOA
will be possible after expiration of the present one. Without this
agreement, BPA is at risk of escalating costs after fiscal year 2001 if
additional funds for fish measures beyond those planned at this time are

37
  Power marketers are subsidiaries of IOUs or independent companies that buy and sell power,
typically on a wholesale basis.



Page 27                                         GAO/AIMD-97-110 Federal Electricity Activities
                            B-276640




                            needed.38 BPA also faces new or additional costs after 2001. First, it plans to
                            implement a phased-in approach to recover 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 new or
                            additional costs that will be incurred after fiscal year 2001 include
                            $806 million of irrigation debt payments and $396 million in payments to
                            the Confederated Tribes of the Colville Reservation for their share of
                            Grand Coulee Dam revenues. These costs, which are discussed further in
                            appendix VIII of volume 2, will be paid out over several decades.

Mitigating Factors Reduce   Several factors mitigate the federal government’s risk of future losses
Probability of Loss         relative to BPA. These factors include certain inherent cost advantages,
                            management actions to reduce operating costs, and an extensive
                            transmission system. We believe that these factors reduce the risk of loss
                            to the federal government after 2001, but that the risk of loss is still
                            reasonably possible. Additionally, BPA is scheduled to have nearly all of its
                            nonfederal debt paid off by 2019, with a substantial decrease in debt
                            service beginning in 2013. 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 reduce the risk to the federal
                            government. As shown in figure 3, BPA’s 1995 average revenue per kWh
                            was more than 15 percent lower than IOUs and POGs in the primary NERC
                            region (Western Systems Coordinating Council) in which BPA operates.




                            38
                             If total federal mitigation costs increase and BPA reduces or caps its fish mitigation expenses after
                            2001, the federal government may have to bear additional costs.



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Figure 3: Average Revenue per kWh
for Wholesale Power Sold in 1995 for
BPA Compared to IOUs and POGs in       4    Cents per kWh
the Western Systems Coordinating
Council Region
                                                            3.19         3.26

                                       3
                                           2.71


                                                   2.18
                                       2




                                       1




                                       0

                                            BPA              IOUs         POGs



                                                    1995

                                                    1996


                                       Note: 1995 data are the latest available for IOUs and POGs. We included BPA’s 1996 average
                                       revenue per kWh to show its almost 20 percent decrease from 1995 to 1996.

                                       Source: GAO analysis of BPA annual reports, preliminary (unaudited) 1995 IOU data from EIA,
                                       and POG data from APPA.




                                       As previously mentioned, BPA is facing significant competition today.
                                       However, BPA believes that its average production costs are less than
                                       others in the Pacific Northwest, as shown in figure 3. If the supply of
                                       surplus power dries up and gas generation costs rise, which BPA believes
                                       will happen, BPA’s low average production costs should improve its
                                       long-term competitive position. This long-term position will be further
                                       improved after 2012, if BPA repays its nonfederal debt as scheduled.

                                       BPA has comparatively low average production costs because of certain
                                       inherent cost advantages over nonfederal utilities. As previously
                                       mentioned, BPA did not recover nearly $400 million of costs associated




                                       Page 29                                        GAO/AIMD-97-110 Federal Electricity Activities
                             B-276640




                             with producing and marketing federal power. In addition, the
                             hydroelectric plants that generate the power marketed by all the PMAs have
                             cost advantages over coal and nuclear generating plants, which generate
                             over 81 percent of the electricity in the United States. BPA’s hydroelectric
                             plants, which were built decades ago, had relatively low construction
                             costs compared to the newer construction of nonfederal utilities. Another
                             key advantage for BPA is that like the other three PMAs, it generally does not
                             pay taxes. Furthermore, interest income to bondholders from BPA’s
                             nonfederal debt is exempt from federal personal income tax and some
                             state income taxes.

                             BPA management has taken significant steps in the last several years to
                             react to the intense wholesale electricity competition in the Pacific
                             Northwest. According to BPA, it reduced its staff from about 3,755 in
                             March 1994 to 3,160 by the end of fiscal year 1996. An additional reduction
                             to 2,755 is planned by fiscal year 1999. In addition, over the last several
                             years, BPA has refinanced much of its Treasury bonds and nonfederal debt
                             to keep its interest expense as low as possible. According to BPA, these
                             staffing and other cost savings will reduce planned expenses by an average
                             of $600 million per year during fiscal years 1997 through 2001 and allow
                             for a 13 percent rate decrease for those years.

                             BPA  also has an extensive transmission system that comprises about
                             75 percent of the bulk power transmission capacity in the Pacific
                             Northwest. BPA has advised us that in the event of BPA being unable to sell
                             its power at a level that recovers all costs, it might be able to use its
                             massive transmission system to help recover stranded costs.39 This could
                             involve allocating stranded generation costs, in whole or in part, to
                             transmission charges.


Risk From TVA Is Remote      At September 30, 1996, TVA had $27.9 billion of debt and $6.3 billion of
Under Current Structure      deferred assets, which leaves TVA with far more financing costs and
but Is Reasonably Possible   deferred assets than its potential competitors. However, we believe that as
                             long as TVA remains in a protected position similar to a traditional
in a Competitive             regulated utility monopoly, the risk of loss to the federal government is
Environment                  remote. If this position changes and TVA is required to compete when
                             wholesale prices are expected to be falling, its high level of fixed costs and
                             deferred assets compared to neighboring utilities increase the risk that the
                             federal government would incur future losses. Despite a number of factors

                             39
                               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.



                             Page 30                                            GAO/AIMD-97-110 Federal Electricity Activities
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                               that mitigate this risk, it is reasonably possible under this scenario that the
                               federal government would incur future losses related to TVA.

                               TVA has two key items that protect it from competition and result in TVA
                               operating like a traditional regulated utility monopoly in its service area.
                               First, contracts with TVA’s distributors (except for Bristol, Virginia)
                               automatically renew each year and require that at least 10 or 15 years’
                               notice be given before they 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.

High Fixed Costs Would Limit   TVA’s regulated monopoly-type position enables it to set its rates at
Flexibility in a Competitive   whatever price is necessary to recover its costs. However, TVA has chosen
Environment                    to defer costs related to its substantial nuclear investment to future years
                               rather than currently including them among the costs being recovered
                               from ratepayers. As a result, TVA had accumulated about $28 billion of debt
                               as of September 30, 1996, which resulted in over $2 billion of interest
                               expense in fiscal year 1996. By not recovering these costs from ratepayers
                               and using the cash to pay off debt in prior years, TVA has developed a high
                               level of fixed costs and deferred assets which will leave it vulnerable to
                               future competition if it loses its protections. This is similar to the situation
                               BPA faced when its high fixed costs limited its flexibility to meet
                               competitive challenges when electricity prices fell sharply in the Pacific
                               Northwest. However, unlike TVA, BPA has no deferred nuclear assets.

                               Our analysis shows that for fiscal year 1996, TVA’s ratio of financing costs
                               to revenue40 was more than twice the average for 11 neighboring utilities
                               and its ratio of fixed financing costs to revenue41 was almost five times
                               higher. 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. Additionally, as TVA’s 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 interest rates decline, TVA’s financing costs would decrease.

                               40
                                 The ratio of financing costs to revenue was calculated by dividing financing costs by operating
                               revenue for fiscal year 1996. The financing costs include interest expense and, for IOUs, also include
                               preferred and common stock dividends to reflect the difference in the capital structures of these
                               entities and TVA.
                               41
                                 The ratio of fixed financing costs to revenue is the same as the financing cost to revenue ratio except
                               that common stock dividends for IOUs are excluded. These dividends are excluded from the IOUs’
                               financing costs because they are not contractual obligations.



                               Page 31                                            GAO/AIMD-97-110 Federal Electricity Activities
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TVA has deferred $6.3 billion in costs associated with its Bellefonte units 1
and 2, and Watts Bar unit 2 that are currently in “mothballed” status. TVA is
treating these assets similar to construction work-in-progress, with the
costs not being recovered from ratepayers.42 In aggregate, TVA has spent
over $26 billion on nuclear plants, which were primarily debt financed.
Most of these costs have not yet been recovered from ratepayers. Other
utilities have been preparing for competition by writing-down their
uneconomical assets at a much faster rate than TVA. As a result, these
utilities have been recovering costs at a much greater pace than TVA and
thus will have greater financial flexibility in the future.

To demonstrate the magnitude of TVA’s deferral of costs, we compared
TVA’s rate of depreciation and its cost deferral to neighboring utilities.
First, TVA’s ratio of accumulated depreciation and amortization to gross
property, plant, and equipment (PP&E) was about 18 percent as of
September 30, 1996, compared to about 36 percent for the 11 neighboring
utilities. This ratio shows that other utilities have already recovered twice
as much of their capital investments percentagewise as TVA. Second, TVA’s
deferred assets as of September 30, 1996 were nearly 20 percent of its
gross PP&E compared to about 3 percent for the IOUs. This ratio clearly
shows that TVA’s deferral of $6.3 billion of costs is unique and out of line
with neighboring utilities. TVA’s ability to recover its substantial capital
costs in a competitive environment is uncertain.

TVA’s vulnerability to wholesale competition without protections was
recently demonstrated when one of its customers, the Bristol Virginia
Utilities Board, announced that it will leave the TVA system for Cinergy,
Inc., in January 1998. Cinergy offered firm wholesale power at 2.59 cents
per kWh for 7 years, 40 percent lower than TVA’s comparable wholesale
rate of 4.3 cents per kWh. 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 1992,43 which allows other utilities
to transmit (wheel) electricity to Bristol over TVA’s power lines. While we
recognize that Cinergy may have offered this power to Bristol at a price
representing its marginal costs, TVA could face this type of competitive
situation regularly if it were to lose its protections from competition.


42
 TVA believes this accounting treatment is justified because there is still a possibility the plants will be
completed. However, given that there has been no construction on these plants for 9 years, we believe
TVA should be recovering these costs from ratepayers. See appendix IX of volume 2 for further
discussion.
43
  As a result of Bristol’s exemption, TVA is required, for a fee, to wheel Cinergy’s power to Bristol.



Page 32                                             GAO/AIMD-97-110 Federal Electricity Activities
                            B-276640




Mitigating Factors Reduce   Several factors mitigate the government’s risk of future loss relative to TVA.
Probability of Loss         These factors include certain inherent cost advantages; management
                            actions to increase revenue, cut operating expenses, and reduce debt; and
                            an extensive transmission system. We believe these factors reduce the risk
                            of loss to the federal government, but the risk of loss is still reasonably
                            possible.

                            TVA has several inherent cost advantages because it is a federal
                            government corporation. First, TVA’s debt receives the highest possible
                            rating from the bond rating services. According to these services, TVA’s
                            creditworthiness is based primarily on its links to the federal government
                            rather than on the criteria applied to a stand-alone corporation.44 As a
                            result, the private lending market has provided TVA with access to billions
                            of dollars of financing at favorable interest rates. 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. Additionally, interest income for TVA’s bondholders is generally
                            exempt from state income taxes, which further lowers TVA’s cost of funds.

                            TVA is exempt from paying income taxes, unlike its neighboring IOUs.
                            Therefore TVA, as a nonprofit entity, does not have to generate the net
                            income that an IOU would need to cover income taxes and provide for 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. This 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 that amounted to about
                            $125 million, or about 2 percent of the total fiscal year 1995 operating
                            revenues of TVA and the distributors. According to EIA, IOUs pay about
                            14 percent of gross revenues for taxes.

                            Another cost advantage is that TVA generates significantly more
                            hydroelectric power than other utilities in the region and purchases
                            hydropower from Southeastern at less than 1 cent per kWh. TVA’s
                            hydropower dams generate about 11 percent of TVA’s power with a
                            relatively low capital investment of about $1.3 billion; on the average,
                            other utilities nationwide generate only about 6 percent of their electricity
                            with hydropower.

                            44
                             In assessing stand-alone corporations, the rating services also consider the strength of parent
                            companies in making debt ratings. Because TVA’s “parent” is the federal government, it has the benefit
                            of the highest bond ratings—Aaa (Moody’s).



                            Page 33                                          GAO/AIMD-97-110 Federal Electricity Activities
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                         TVA management has taken significant steps to reduce its expenses.
                         According to TVA, it reduced its staff from about 34,000 in 1988 to about
                         16,000 in 1996 and plans further reductions in 1997. In addition, TVA has
                         refinanced its debt to keep its interest expense as low as possible. The
                         completion of TVA’s Watts Bar 1 and restarting of its Browns Ferry 3
                         nuclear power units—a major reason for TVA’s increasing debt in recent
                         years—is another important step. According to TVA, it has internally
                         capped its debt at about $28 billion and plans to finance its future capital
                         expenditures from operations. These plans and actions are consistent with
                         those of IOUs in preparation for competition.

                         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) limit annual capital expenditures to
                         $595 million, (3) reduce debt by about 50 percent from $27.9 billion as of
                         September 30, 1996, to $13.8 billion by fiscal year 2007, and (4) reduce its
                         total cost of power by about 16 percent 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 will be reduced. In addition to the
                         above planned 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.

                         A final mitigating factor is TVA’s extensive transmission system, which
                         covers nearly 100 percent of the transmission service available in its
                         service area. If TVA is exposed to competition and is unable to sell its
                         power at a level that recovers all costs, it may be able to use its
                         transmission system to recover some stranded costs.


                         As agreed with your offices, we did not
Objectives, Scope,
and Methodology      •   estimate the forgone revenue for federal, state, or local governments
                         resulting from the tax-exempt status of the RUS borrowers, the PMAs, or TVA;
                     •   estimate the forgone revenue for federal and state governments resulting
                         from tax-exempt debt instruments issued by TVA or related to Western or
                         BPA’s nonfederal debt;




                         Page 34                              GAO/AIMD-97-110 Federal Electricity Activities
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                            •   assess the reasonableness of the methodologies used by the operating
                                agencies to allocate power-related costs to the PMAs for recovery; or
                            •   quantify the amount of potential future losses to the federal government.

                                A detailed discussion of our objectives, scope, and methodology, including
                                additional items not included in the scope of our review, is contained in
                                appendix II of volume 2 to this report. Appendix II also includes detailed
                                explanations of the calculations of various estimates used in the report
                                and the criteria we used to assess cost recovery and the likelihood that the
                                federal government will incur future losses relating to RUS, the PMAs, and
                                TVA.


                                When appropriate, we used audited numbers from RUS, RUS’ borrowers,
                                PMA, and TVA fiscal years 1996, 1995, and earlier financial statements
                                included in their annual reports. We conducted our review from
                                January 1997 through July 1997 in accordance with generally accepted
                                government auditing standards. We received written comments on a draft
                                of this report from USDA, the three PMAs, BPA, and TVA. These comments are
                                discussed in the following section and are reprinted in volume 2,
                                appendixes X through XIII. We also received technical oral comments
                                from the Corps of Engineers and the Bureau of Reclamation. We evaluated
                                their comments and incorporated changes, where appropriate, into
                                volumes 1 and 2 of our final report.


                                The comments from USDA, the three PMAs, BPA and TVA generally focused on
Agency Comments                 our analysis of net financing costs and the federal government’s risk of
and Our Evaluation              future financial losses related to the electricity-related activities of these
                                entities. All of these entities generally disagreed with our estimates of their
                                net financing costs. In addition, they also disagreed with our assessment of
                                the federal government’s risk of future financial losses related to their
                                electricity-related activities.


Net Financing Costs             USDA,the three PMAs, and BPA took issue, for varying reasons, with our
                                estimate of net financing costs.

Department of Agriculture       USDA  disagreed with our use of the portfolio methodology45 in estimating
                                net financing costs on RUS outstanding federal debt. It noted that our
                                analysis resulted in larger estimates of net financing costs to the federal
                                government than the estimates obtained in USDA’s application of the credit

                                45
                                  See appendix II of volume 2 of this report for a description of the portfolio methodology.



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                               reform methodology that were discussed in our April 1997 report.46 As we
                               stated in our current report, the majority of outstanding RUS electricity
                               loans and guarantees, approximately 90 percent, were made prior to 1991
                               and therefore are not required to be reported under credit reform.
                               Additionally, because the USDA Inspector General deemed the RUS credit
                               reform estimates unreliable, we chose to use actual costs incurred rather
                               than any credit reform estimates for our analysis.

The Power Marketing            The three PMAs and BPA disagreed with our estimate of the net financing
Administrations                costs. While the comments regarding the net financing cost estimates were
                               not consistent and in one instance contradictory, two broad common
                               issues were raised: (1) disagreement with our use of the portfolio
                               methodology for estimating the net financing costs to the federal
                               government for appropriated debt, including the use of the weighted
                               average interest rate on outstanding long-term Treasury bonds, and (2) the
                               assertion that the PMAs’ appropriated debt is analogous to a mortgage loan.

Disagreement With the Use of   The three PMAs stated that they believe the use of the portfolio
the Portfolio Methodology to   methodology assumes that both the PMA interest rate and Treasury’s cost
Estimate Net Financing Costs   of funds are variable, so the cost difference on any individual investment
                               varies from year to year. They stated that this is equivalent to assuming
                               that the PMA appropriated debt should be refinanced annually. The three
                               PMAs stated that comparing the interest rates assigned to PMA financings to
                               Treasury rates in the years the financings were provided (loan-by-loan
                               methodology) would be a more accurate way of determining the net
                               financing cost. BPA also suggested a loan-by-loan approach, stating that
                               determining the cost to Treasury of providing BPA’s financing should be
                               done “on the basis of an assessment of each loan incrementally, as a
                               commercial lender would do.” Finally, the three PMAs and BPA disagreed
                               with our using the interest rate on Treasury’s outstanding bond portfolio
                               to estimate net financing costs on outstanding appropriated debt.

                               As discussed in appendix II of volume 2 of this report, we defined the net
                               financing cost to the federal government as the difference between
                               Treasury’s borrowing cost or interest expense and the interest income
                               received from 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

                               46
                                 Rural Development: Financial Condition of the Rural Utilities Service’s Loan Portfolio
                               (GAO/RCED-97-82, April 11, 1997). As stated in this report, we did not assess the accuracy of RUS’
                               reported subsidy cost estimates or the accuracy of the system used by RUS to derive such estimates
                               under credit reform.



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outstanding at September 30, 1996. Each of these forms of federal debt had
different terms and thus required us to apply variations of our basic
methodology in assessing whether there was a net financing cost and, if
so, estimating the amount.

For the PMAs’ appropriated debt, the portfolio methodology best captures
the combined impact of the four distinct aspects of the net financing cost
that we identified: (1) the difference between the PMAs’ borrowing rate and
Treasury’s borrowing rate for securities of similar maturity at the time the
appropriation was made (interest rate spread), (2) the PMAs’ ability to
repay the highest interest rate debt first (prepayment option), (3) the
interest rate risk arising from Treasury’s general inability to refinance or
prepay outstanding debt in times of falling interest rates (Treasury
borrowing practices), and (4) the difference in the maturities of the three
PMAs’ and BPA’s appropriated debt and Treasury’s bonds (maturity
differential). The loan-by-loan methodology suggested by the three PMAs
and BPA is limited in that it captures only that portion of the net financing
cost arising from the interest rate spread and not the other three aspects
of that cost.

We noted in appendix II of volume 2 of this report that as a comparison to
our portfolio analyses, we did perform loan-by-loan assessments to
estimate the net financing cost to the federal government for one of the
three PMAs—Southwestern—as well as for BPA and RUS. In our loan-by-loan
analyses, we attempted to match the PMAs’ appropriated debt and RUS
federal debt with Treasury borrowing. In these analyses, we assumed that
to provide financing for up to 50 years for a PMA project and 40 years for
RUS debt, Treasury had to borrow an equivalent amount via the sale of
long-term bonds. Because Treasury does not generally borrow for more
than 30-year terms, in the loan-by-loan analyses, we also assumed that
Treasury had to refinance each borrowing to extend the financing to the
PMAs or RUS borrowers for the remainder of the terms of the debt.


Our loan-by-loan analyses resulted in a net financing cost for fiscal year
1996 that was higher than under the portfolio methodology for two of the
three entities (BPA and Southwestern) and the same for the third (RUS). For
BPA, the net financing cost for fiscal year 1996 was about $445 million
under the loan-by-loan analysis (versus $377 million under the portfolio
analysis), for Southwestern it was about $54 million (versus $42 million
under the portfolio analysis), and for RUS it was about $874 million (the
same as under the portfolio analysis).




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                              The criticism of our use of the portfolio methodology is also inconsistent
                              with another BPA comment asserting that a portfolio methodology estimate
                              of net financing costs using a lower Treasury interest rate—the rate on
                              Treasury’s entire portfolio of outstanding marketable securities, including
                              short-term securities—would be appropriate. BPA stated that in using only
                              long-term Treasury debt to gauge Treasury’s cost of funds for appropriated
                              debt, our report inflates Treasury’s true cost of funds and, therefore, the
                              net cost to the government of BPA’s operations. BPA stated that a more
                              appropriate measure of Treasury’s cost of carrying this debt is Treasury’s
                              composite rate for all marketable interest-bearing debt, which was about
                              6.7 percent at the end of fiscal year 1996.

                              The composite interest rate that BPA proposed includes recently issued
                              short-term Treasury bills and some notes with maturities of only several
                              months. Using this composite interest rate that includes short-term
                              securities is inappropriate because it would match short-term Treasury
                              borrowing costs with long-term PMA appropriated debt. Because Treasury’s
                              bond portfolio includes debt issued over the last several decades, the
                              average interest rate on this portfolio is a reasonable approximation of the
                              federal government’s cost of funds relating to the PMAs’ appropriated debt,
                              which also was incurred over the last several decades.

                              Moreover, the interest rate BPA is to pay on its appropriated debt under the
                              Omnibus Consolidated Rescissions and Appropriations Act of 1996
                              supports our position that a long-term Treasury rate is the correct rate to
                              use in our portfolio analysis. Under this act, that interest rate is based on
                              long-term Treasury bond interest rates.

Assertion That Financings     The three PMAs and BPA also asserted that appropriated debt is analogous
Provided by Treasury Are      to fixed-rate mortgage loans issued by a commercial lender. The three
Analogous to Mortgage Loans   PMAs stated that their concern over our estimate of net financing costs
                              might be best explained by using a mortgage loan example. They stated
                              that a fixed interest rate is assigned to each investment that the PMAs’
                              customers are required to repay, just as a homeowner receives a fixed rate
                              mortgage from a lender. They further stated that to assert that the PMAs
                              impose a net cost to Treasury in a year in which market interest rates have
                              risen above the interest rates on the PMAs’ appropriated debt is equivalent
                              to saying that the homeowner imposes a net cost on a lender whenever
                              market rates for home loans rise above the homeowner’s fixed mortgage
                              rate. Similarly, BPA stated that a 30-year fixed rate mortgage entered into in
                              a year with low interest rates would not result in a cost to the lender
                              simply because interest rates increased over time.



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We do not agree that the PMAs’ financing is analogous to a mortgage
lending situation for several reasons. First, in a mortgage-type lending
arrangement, if the lender wants to remain in business, it establishes a
spread between the rate charged the borrower and the rate it must pay for
the capital it lends. In the case of the PMAs’ appropriated debt, the PMAs do
not pay higher interest rates than the interest rates Treasury pays on its
bonds. On the contrary, in most instances the rates the PMAs paid on
currently outstanding appropriated debt were significantly lower than the
rates Treasury paid when the financings were provided. In addition, the
PMAs do not pay any transaction fees (for example, points or closing costs)
associated with the financings, which homeowners generally pay. The
highest interest rate the PMAs are subject to for new financing is based on
the rates on long-term Treasury securities issued the previous year, which
generally have maturities of 30 years or less even though the repayment
periods for the PMAs’ appropriated debt are up to 50 years. No attempt is
made to charge a differential or take into account the greater risk of
having appropriated debt outstanding for 50 years; in contrast, 30-year
mortgages have higher interest rates than 15-year mortgages. Also, the
PMAs are able to receive interest rates based on Treasury bonds that are
“risk-free.” If the PMAs were required to obtain financing in the private
market, without any implicit or explicit federal guarantee, they would
likely pay interest rates higher than the risk-free Treasury rate.

Furthermore, a mortgage lender typically requires that borrowers repay
their loans, including principal and interest payments, on a fixed schedule,
while the PMAs are not required to make fixed principal payments. Instead,
the PMAs’ appropriated debt is similar to a balloon loan that is due in full at
the end of the term—up to 50 years for the PMAs. The PMAs are required to
repay debt with the highest interest rate first to minimize interest expense.
Since the PMAs’ interest expense is minimized, this requirement minimizes
interest income to Treasury and maximizes Treasury’s interest rate risk.
The PMAs currently have debt outstanding from decades ago at extremely
low and outdated interest rates and upon which no principal has been
paid. If the PMAs’ appropriated debt had been paid back like a mortgage,
their current weighted-average interest rates would be far higher. The
result of this type of arrangement, along with Treasury’s general inability
to call its outstanding bonds, is that the interest income Treasury receives
on the PMAs’ appropriated debt is considerably less than the interest
Treasury pays to bondholders on a comparable amount of Treasury debt.
We are not aware of any mortgage lender who would be able to remain in
business over the long term if it operated similarly.




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Additional Net Financing Cost       BPA stated that our draft report disregards the fact that the interest charges
Comments by BPA                     BPA pays on its appropriated debt were determined years ago using interest
                                    rates prevailing at that time. While the interest rates assigned to some
                                    Federal Columbia River Power System (FCRPS) appropriations
                                    approximated Treasury’s long-term interest rate, BPA’s statement is not
                                    factually accurate. Over the last 4 decades, BPA has incurred substantial
                                    debt at below-Treasury interest rates, as shown by the following examples:

                                •   BPA incurred over $250 million in appropriated debt in 1969 at an interest
                                    rate of 2.5 percent when Treasury’s long-term bond rate was 6.67 percent;
                                    less than 1 percent of this has been repaid.
                                •   BPA incurred over $250 million in appropriated debt at 2.5 percent in 1975
                                    when Treasury’s long-term bond rate was 7.99 percent; less than 1 percent
                                    of this has been repaid.
                                •   BPA incurred over $399 million in appropriated debt at 3.25 percent in 1982
                                    when Treasury’s long-term bond rate was 12.76 percent; none of this has
                                    been repaid.
                                •   BPA currently has outstanding appropriated debt bearing interest at
                                    2.5 percent that was borrowed as recently as 1992 when Treasury’s
                                    long-term bond rate was 7.67 percent, and 3.125 and 3.25 percent debt
                                    incurred as recently as 1990 when long-term Treasury bond rates were
                                    8.61 percent.

                                    In addition, BPA stated that we were inconsistent in assessing the net
                                    financing cost for BPA and TVA appropriated debt because we used a
                                    9.0 percent interest rate to assess BPA’s net financing cost but used a
                                    6.87 percent interest rate to determine the federal government’s net cost of
                                    providing financing to TVA. We disagree with BPA’s assessment. Since the
                                    terms of BPA’s and TVA’s appropriated debt differ markedly, it is reasonable
                                    to reflect this in assessing the net financing cost to the federal
                                    government. TVA is generally required to make payments on its outstanding
                                    principal balance every year, whereas BPA is required to pay outstanding
                                    principal only in the year of maturity. Also, the interest rate on TVA’s
                                    appropriated debt is revised annually to reflect the cost to Treasury of
                                    providing the financing. In contrast, BPA is allowed to repay appropriated
                                    debt with the highest interest rate first and keep appropriated debt with a
                                    low interest rate on the books for decades.

                                    Since TVA appropriated debt is in effect refinanced annually, it can
                                    reasonably be assigned an interest rate based on Treasury’s composite
                                    interest rate on all outstanding marketable securities, which includes
                                    short-term securities. Moreover, the different terms result in different



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                                exposures to interest rate risk. TVA bears interest rate risk in that if
                                Treasury’s interest rates rise, TVA’s interest expense rises. In contrast, once
                                BPA’s interest rates are assigned, they remain the same over the life of the
                                debt. As a result, BPA bears interest rate risk only in the unlikely event that
                                Treasury rates fall below BPA’s weighted-average interest rate of
                                3.5 percent. 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. Moreover, TVA’s appropriated debt currently carries a
                                weighted-average interest rate of 6.87 percent, while BPA’s
                                weighted-average rate is 3.5 percent.

                                BPA also stated that we inadequately addressed the restructuring of BPA’s
                                appropriated debt and that we “hint” that BPA has an imbedded interest
                                rate advantage that the Congress has ignored. In making this observation,
                                BPA appears to be suggesting that the restructuring of its appropriated debt
                                has permanently eliminated any net financing cost to the federal
                                government.

                                We do not agree. Under the terms of BPA’s appropriated debt restructuring,
                                more than $2.5 billion of appropriated debt will be written off in exchange
                                for increasing the interest rates on BPA’s revised appropriated debt balance
                                to market interest rates. BPA will also pay an additional $100 million over
                                the remaining terms of the debt. Other than this $100 million, the net cash
                                flow to Treasury is essentially unchanged as a result of the restructuring.
                                We acknowledge that Treasury will receive $100 million more under the
                                restructured repayment plan than under the existing arrangement if BPA
                                pays off the debt when it matures. However, this $100 million is less than
                                one-third of the $377 million net financing cost we estimate that Treasury
                                incurred in 1996 alone. This net negative cash flow to the federal
                                government will continue as long as the appropriated debt and the
                                corresponding Treasury debt are outstanding.

Additional Net Financing Cost   TVA suggested that our report include an income item of approximately
Comments by TVA                 $100 million in our presentation of “annual costs to the government.” It
                                contends that this amount represents what TVA pays Treasury each year in
                                excess of the government’s current cost of financing TVA’s Federal
                                Financing Bank (FFB) loans. We disagree. Treasury’s current interest rate
                                is not an appropriate measure of its cost of financing loans issued in the
                                past. Rather, the interest rates in effect at the time the loans were issued
                                represents Treasury’s cost. Because FFB is charging TVA the long-term
                                borrowing rate of similar Treasury debt at the time the loan was made, the



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                               federal government is receiving a return sufficient to cover its borrowing
                               costs.

                               If TVA is permitted to refinance these loans without penalty, the federal
                               government will suffer a significant loss. This loss represents the
                               difference between the interest rate at the time of the borrowing and the
                               interest rate on current debt Treasury could avoid incurring today. In 1995,
                               the Congressional Budget Office (CBO) was asked to review proposed
                               legislation that would have authorized TVA to prepay the $3.2 billion in
                               loans made by FFB without paying the prepayment premiums. CBO
                               estimated that enacting such legislation in 1996 would increase federal
                               outlays by about $120 million per year through 2002 with amounts
                               declining thereafter until the last notes matured in the year 2016. This
                               proposed legislation was never introduced.


Risk Assessment                Several of the entities commented on our use of average revenues per kWh
                               as an indicator of cost competitiveness and risk. In addition, each entity
                               commented on our assessment of the risk of future financial losses.

Disagreement With the Use of   The three PMAs and USDA disagreed with our use of average revenue per
Average Revenue per            kWh to compare utilities’ competitiveness.47 The three PMAs stated that the
Kilowatthour to Compare        use of average revenue per kWh is overly simplistic and may mislead the
Utilities’ Competitiveness     report’s readers about the magnitude and causes of the difference in costs
                               between the PMAs and other utilities. The three PMAs stated that they do not
                               believe that average revenue per kWh takes into account the differences in
                               the types of power being sold by different utilities. They stated that a more
                               accurate measure would be to compare similar products being offered by
                               different utilities. USDA officials stated that many variables not addressed
                               in our analysis could significantly alter any comparison.

                               We believe that average revenue per kWh is a strong indicator of the
                               relative power production costs of the PMAs, TVA, and RUS G&T borrowers
                               compared to IOUs and POGs. For the three PMAs, RUS G&T borrowers, and
                               POGs, average revenue per kWh should equal cost over time because each
                               operates as a nonprofit organization that recovers costs through revenues.
                               This assumes that the entity’s competitive position is such that it can
                               charge sufficiently high rates to recover all costs from customers. For IOUs,
                               average revenue per kWh should represent cost plus the regulated rate of
                               return. Given that a large portion of an IOU’s rate of return (net income) is

                               47
                                BPA also had a technical comment on our use of average revenues per kWh, which we address in
                               appendix XII of volume 2 of this report.



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                             used to pay common stock dividends,48 which is a financing cost, average
                             revenue per kWh, while somewhat higher because it includes a profit, is a
                             reasonable approximation of IOUs’ power production costs. In addition,
                             analysts and bond rating agencies commonly use average revenue per kWh
                             in assessing the competitiveness of power rates.

                             We do recognize, however, that using average revenue per kWh as an
                             analytical tool has some limitations. We clearly state in appendix III of
                             volume 2 of this report that the price that any one utility charges another
                             for wholesale energy comprises numerous transaction-specific factors,
                             including fees charged for reserving a portion of capacity, consumption
                             during peak and off-peak periods, and the use of the facilities. In appendix
                             III, we have also clarified our discussion of the current electricity market,
                             in which utilities are generally able to recover their fixed costs from retail
                             customers. Thus, when competing for new wholesale customers, utilities
                             with excess capacity and the ability to recover fixed costs from retail
                             customers are able to sell surplus power at less than full production cost
                             (that is, marginal cost). However, despite these limitations, average
                             revenue per kWh is a good indicator of production costs since, over time,
                             utilities must recover all costs to remain in business.

                             The PMAs also stated that because of the variability in output of certain
                             hydropower projects, our use of average revenue per kWh to indicate
                             competitiveness could result in wide variations in a PMA’s competitive
                             position from year to year. To address this concern, in this report and our
                             September 1996 report, we compared the overall average revenue per kWh
                             for the three PMAs, IOUs, and POGs from 1990 through 1995.49 In each year,
                             the overall average revenue per kWh for each of the three PMAs were lower
                             than IOUs and POGs by at least 40 percent. This 6-year comparison shows
                             that the use of average revenue per kWh does not result in wide
                             fluctuations in assessing the PMAs’ competitiveness from year to year.

Additional Risk Assessment   Each entity commented on our assessment of the risk to the federal
Comments                     government of future financial losses related to that entity. USDA did not
                             agree with our assessment that it is probable that some RUS borrowers
                             who are not currently financially distressed will require loan write-offs in
                             the future. The three PMAs asserted that our assessment of risk of future

                             48
                               The amount of IOUs’ net income paid out in common stock dividends averaged 79 percent over the
                             last 5 years.
                             49
                               In appendix VII of volume 2 of this report and appendix V of our September 1996 report, we also
                             compared individual rate-setting systems of the three PMAs to IOUs and POGs in their respective
                             regions. See Power Marketing Administrations: Cost Recovery, Financing, and Comparison to
                             Nonfederal Utilities (GAO/AIMD-96-145, September 19, 1996).



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                            losses is overstated. BPA stated that our risk assessment did not adequately
                            take into account changes which will occur in the year 2012, when BPA
                            asserts that the price of its wholesale power should be well below market.
                            TVA stated that our assessment of the federal government’s risk of loss is
                            more negative than is warranted.

Department of Agriculture   USDA  agreed that in the near future, some write-offs of loans related to old
                            investments by borrowers that are currently financially stressed are
                            probable. However, USDA disagreed that it is probable that other borrowers
                            that are not currently financially stressed will also require write-offs of
                            their loans. USDA stated that it does not believe that the past history of
                            power plant investment is useful in projecting the future in a new
                            competitive, restructured, unbundled infrastructure. We disagree. Because
                            past investments must be recovered and directly impact current
                            production costs, these investments will be key factors in the ability of RUS
                            G&Ts to compete in a deregulated environment. Our analysis shows that 27
                            of the 33 G&T borrowers (82 percent) had higher production costs than the
                            IOUs in their regions. For this and other reasons discussed in our report, it
                            is probable that the federal government will eventually incur losses on
                            some of these G&T borrowers. In a May 1995 report, Moody’s Investors
                            Service reported, “In a more competitive environment, a G&T’s production
                            costs relative to those of IOUs will become increasingly important.
                            Competitively priced power resulting from low generation and purchased
                            power costs is essential for co-ops to maintain their place in the electric
                            utility industry of the future.”

The Three Power Marketing   The three PMAs asserted that our assessment of risk of future losses is
Administrations             overstated and that the risks of future financial losses from four projects
                            (Russell, Truman, Mead-Phoenix, and Washoe) are not “probable.” We
                            disagree. As discussed in our report, each of these projects faces
                            operational and/or financial difficulties. Increasing competition in the
                            electricity industry is expected to lead to falling prices, which will put
                            even more competitive pressure on these projects and could result in
                            financial difficulties at others. For the reasons detailed in our report, these
                            four projects all meet the probable loss criteria if they do not become fully
                            operational (Russell and Truman) or certain proposals to mitigate the risk
                            are not implemented or are not successful (Mead-Phoenix and Washoe).
                            Because the likelihood that all four projects can be successfully turned
                            around is, in our opinion, remote, a probable risk assessment overall is
                            appropriate.




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Bonneville Power                 BPA stated that by concluding that it is “reasonably possible” that the
Administration                   federal government will incur a loss from BPA’s operations after fiscal year
                                 2001, we did not describe the limited, transitional nature of the risk. BPA
                                 asserted that the risk is confined to the approximately 10 years after 2001,
                                 following which BPA’s costs and the price of its wholesale power should be
                                 well below market and the risk to the government “remote.” We agree that,
                                 all else being equal, if BPA pays off its nonfederal debt as planned, the
                                 federal government’s risk begins to decrease after 2012. After that year,
                                 nuclear project debt service costs are expected to decrease from an
                                 average of about $570 million (about 29 percent of BPA’s total operating
                                 expenses for fiscal year 1996) annually to an average of about $304 million
                                 annually for the period from 2013 through 2018. However, the risk of
                                 future financial loss to the federal government would not become remote
                                 until 2019, when BPA’s scheduled debt service payments drop to less than
                                 $3 million and decrease further in the following years.

Tennessee Valley Authority       TVA stated that our long-term assessment of the federal government’s risk
                                 of loss due to its involvement in TVA is more negative than is warranted.
                                 TVA stated that although there are many uncertainties about the future of
                                 the utility industry, it believes that the steps it has taken over the past 10
                                 years and future plans to improve TVA’s competitiveness will allow it to be
                                 successful in a restructured electric utility marketplace.

                                 We disagree. As also discussed in our August 1995 report,50 if TVA is
                                 required to compete when wholesale prices are expected to be falling, its
                                 high level of fixed costs and deferred assets compared to neighboring
                                 utilities make it reasonably possible that the government would incur
                                 future losses. The following facts, among others, support our position.

                             •   At September 30, 1996, TVA had $27.9 billion of debt and $6.3 billion of
                                 deferred assets, which leaves TVA with far more financing and deferred
                                 costs than its potential competitors. For fiscal year 1996, we found that
                                 TVA’s ratio of financing costs to revenue was more than twice the average
                                 of 11 neighboring utilities. In addition, TVA’s deferred assets at
                                 September 30, 1996, were nearly 20 percent of its gross PP&E, compared to
                                 about 3 percent for the IOUs.
                             •   TVA’s vulnerability to future competition, without protections, was recently
                                 demonstrated when one of its customers, the Bristol Virginia Utilities
                                 Board, announced that it will leave the TVA system for Cinergy, Inc.
                                 beginning on January 1, 1998. Cinergy offered Bristol firm, delivered

                                 50
                                  Tennessee Valley Authority: Financial Problems Raise Questions About Long-term Viability
                                 (GAO/AIMD/RCED-95-134, August 17, 1995).



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    wholesale power at 2.59 cents per kWh for 7 years—40 percent lower than
    TVA’s comparable wholesale rate of 4.3 cents per kWh.
•   Through the third quarter of fiscal year 1997, TVA reported a net loss of
    about $176 million.
•   In May, 1997, the Board of a second TVA distributor—Paducah,
    Kentucky—voted to give TVA its 10-year notice to cancel its power
    contract.
•   TVA’s five largest distributors, which currently buy about one-third of TVA’s
    power, have indicated that they plan to negotiate changes to their
    contracts with TVA.

    In addition, as discussed in our current report, 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 of the restructured
    marketplace. TVA’s planned actions support the position we have taken in
    this and our August 1995 report about the impact TVA’s high level of
    financing costs and deferred assets will have on its ability to compete in a
    deregulated marketplace. In announcing the 10-year plan, TVA stated that
    the actions described in the plan were “deemed critical for TVA to provide
    power at projected market prices of the future.” TVA’s Chief Financial
    Officer also stated “To remain competitive in the changing electrical-utility
    market, we must reduce our total cost of power and become more
    financially flexible to respond quickly to changing customer demands.” We
    agree with these recent TVA statements.


    As agreed with your offices, unless you publicly announce its contents
    earlier, we plan no further distribution of this report until 30 days from the
    date of this report. At that time, we will send copies to appropriate House
    and Senate committees; the Ranking Minority Members of the House
    Committee on the Budget and the Subcommittee on Water and Power
    Resources, House Committee on Resources; interested Members of the
    Congress; the Secretary of Agriculture; the Secretary of the Interior; the
    Secretary of Energy; the Secretary of Defense; the Director, Office of
    Management and Budget; the Chairman of the Board of Directors of the
    Tennessee Valley Authority; and other interested parties. We will make
    copies available to others upon request.




    Page 46                               GAO/AIMD-97-110 Federal Electricity Activities
           B-276640




           Please call me at (202) 512-8341 or Gregory Kutz, Associate Director for
           Governmentwide Audits, at (202) 512-9505 if you or your staffs have any
           questions. Major contributors to this report are listed in appendix XIV of
           volume 2.




           Linda M. Calbom
           Director, Civil Audits




(913805)   Page 47                              GAO/AIMD-97-110 Federal Electricity Activities
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