Federal Electricity Activities: The Federal Government's Net Cost and
Potential for Future Losses (Letter Report, 09/19/97,
GAO/AIMD-97-110,AIMD-97-110A).
Pursuant to a congressional request, GAO reviewed federal electricity
activities, focusing on the: (1) federal government's net recurring cost
from the electricity-related activities at the Department of
Agriculture's Rural Utilities Service (RUS), the Department of Energy's
power marketing administrations (PMA), and the Tennessee Valley
Authority (TVA) for fiscal year (FY) 1996 and, where possible, the
cumulative net cost for FY 1992 through 1996; and (2) likelihood of
future losses beyond the net recurring costs to the federal government
from these entities.
GAO noted that: (1) the federal government incurs net costs of over a
billion dollars annually in supporting the electricity-related
activities of RUS and the PMAs; (2) GAO estimates that the net costs to
the federal government for FY 1996 totaled about $2.5 billion--$0.4
billion for BPA, $0.2 billion for the three PMAs, and about $1.9 billion
for RUS, including about $982 million in RUS loan write-offs; (3) the
federal government is exposed to additional future losses beyond the
recurring net costs resulting from the government's more than $84
billion in direct and indirect financial involvement in the
electricity-related activities of RUS, the PMAs, and TVA as of September
30, 1996; (4) these potential future losses relate to the possibility
that RUS borrowers, the PMAs, and TVA would be unable to repay the full
$53 billion in debt owed to the federal government or that the federal
government would incur unreimbursed costs as a result of actions it took
to prevent default or breach of contract on the $31 billion in
nonfederal debt; (5) this risk exists because certain RUS borrowers, the
PMAs (to varying degrees) and TVA are financially vulnerable primarily
as a result of uneconomical construction projects and the accumulation
of substantial debt, which have resulted in high fixed costs; (6) the
Southeastern, Southwestern, and Western PMAs generally market wholesale
power that consistently costs at least 40 percent less than power sold
by nonfederal utilities and are therefore currently competitively sound
overall; (7) however, the three PMAs maintain this overall soundness in
part because they do not recover all power-related costs; (8) if they
were required to recover some or all of these power-related costs, their
ability to remain competitive might be impaired and the risk of future
financial loss to the federal government increased; (9) also, each has
one or a few projects or rate-setting systems with problems that, taken
as a whole, make the risk of some loss to the federal government
probable; and (10) for TVA, the risk that the federal government will
incur losses is remote as long as TVA retains a position similar to a
traditional regulated utility monopoly in its service area.
--------------------------- Indexing Terms -----------------------------
REPORTNUM: AIMD-97-110
AIMD-97-110A
TITLE: Federal Electricity Activities: The Federal Government's
Net Cost and Potential for Future Losses
DATE: 09/19/97
SUBJECT: Electric utilities
Loan repayments
Federal corporations
Utility rates
Cost analysis
Competition
Losses
Intergovernmental fiscal relations
Financial analysis
Energy marketing
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Cover
================================================================ COVER
Report to Congressional Requesters
September 1997
FEDERAL ELECTRICITY ACTIVITIES -
APPENDIXES TO THE FEDERAL
GOVERNMENT'S NET COST AND
POTENTIAL FOR FUTURE LOSSES
VOLUME 2
GAO/AIMD-97-110A
Federal Electricity Activities
(913805)
Abbreviations
=============================================================== ABBREV
AEAN - aggregate entry age normal
APPA - American Public Power Association
ASCC - Alaska Systems Coordinating Council
BPA - Bonneville Power Administration
CBO - Congressional Budget Office
CFTE - contractor full-time equivalent
CWIP - construction work-in-progress
CSRS - Civil Service Retirement System
CVP - Central Valley Project
CVPIA - Central Valley Project Improvement Act
DOE - Department of Energy
DOJ - Department of Justice
ECAR - East Central Area Reliability Coordination Agreement
EIA - Energy Information Administration
EPAct - Energy Policy Act of 1992
ERCOT - Electric Reliability Council of Texas
FCRPS - Federal Columbia River Power System
FERC - Federal Energy Regulatory Commission
FERS - Federal Employee Retirement System
FFB - Federal Financing Bank
FTE - full-time equivalent
GAAP - generally accepted accounting principles
G&T - generation and transmission
IOU - investor-owned utility
IPP - independent power producer
kWh - kilowatthour
KPMG - KPMG Peat Marwick
MAAC - Mid-Atlantic Area Council
MAIN - Mid-America Interconnected Network
MAPP - Mid-Continent Area Power Pool
MOA - memorandum of agreement
NERC - North American Electric Reliability Council
NPCC - Northeast Power Coordinating Council
NRC - Nuclear Regulatory Commission
OMB - Office of Management and Budget
OPM - Office of Personnel Management
O&M - operations and maintenance
PMA - power marketing administration
POG - publicly owned generating utility
PP&E - property, plant and equipment
PURPA - Public Utilities Regulatory Policies Act of 1978
RDA - Rural Development Administration
REA - Rural Electrification Administration
RUS - Rural Utilities Service
SERC - Southeastern Electric Reliability Council
SEPA - Southeastern Power Administration
SFAS - Statement of Financial Accounting Standards
SFFAS - Statement of Federal Financial Accounting Standards
SPP - Southwest Power Pool
SWPA - Southwestern Power Administration
TVA - Tennessee Valley Authority
UKW - Urbach Kahn & Werlin
USDA - United States Department of Agriculture
WAPA - Western Area Power Administration
WPPSS - Washington Public Power Supply System
WSCC - Western Systems Coordinating Council
PREFACE
============================================================ Chapter 0
This volume provides the appendixes to our report, Federal
Electricity Activities: The Federal Government's Net Cost and
Potential for Future Losses, Volume 1. It contains background
information on the federal entities included in our review: the
Department of Agriculture's Rural Utilities Service (RUS); four power
marketing administrations of the Department of Energy--the
Southeastern Power Administration, the Southwestern Power
Administration, the Western Area Power Administration, and the
Bonneville Power Administration; and the Tennessee Valley Authority.
This volume also (1) contains a detailed explanation of our
objectives, scope, and methodology in carrying out this review, (2)
provides additional information on the likelihood of future losses to
the federal government from the electricity-related activities of
these entities, and (3) provides further details on the federal
government's net costs related to these activities. The 14
appendixes in this volume are organized as follows:
-- Appendix I contains background information on the entities and
the status of deregulation and competition in the electric power
industry.
-- Appendix II contains our objectives, scope, and methodology.
-- Appendix III provides information on our use of average revenue
per kilowatthour to assess competitiveness.
-- Appendix IV provides further details on the entities' net costs.
-- Appendix V provides additional information on RUS' financing
costs.
-- Appendixes VI through IX provide additional information on the
likelihood that the federal government will incur future losses
due to these entities.
-- Appendixes X through XIII contain the written comments on a
draft of this report from each of these entities.
-- Appendix XIV lists the major contributors to this report.
If you have any questions concerning this review, please call me at
(202) 512-8341 or Gregory D. Kutz, Associate Director,
Governmentwide Audits, at (202) 512-9505.
Linda M. Calbom
Director, Civil Audits
BACKGROUND
=========================================================== Appendix I
The electricity industry is changing in response to the regulatory
environment and the advent of competition. As discussed in volume 1
and the related appendixes in this volume, the federal government
will be affected by these changes because of its involvement in the
electric power industry. Several federal government entities are
directly or indirectly involved in electricity generation,
transmission, and distribution. They include the Rural Utilities
Service, the five federal power marketing administrations, and the
Tennessee Valley Authority.\1
--------------------
\1 Additionally, many of the federal hydroelectric dams that generate
power were built and are operated by the Corps of Engineers or the
Bureau of Reclamation. Other federal players involved in electricity
generation, transmission, and distribution include the Bureau of
Indian Affairs under the Department of the Interior and the
International Boundary and Water Commission under the State
Department.
LEGISLATIVE CHANGES CREATE A
COMPETITIVE ELECTRICITY MARKET
--------------------------------------------------------- Appendix I:1
Historically, investor-owned utilities (IOUs) and other electricity
providers have operated as regulated monopolies. Under traditional
utility regulations, IOUs were generally required to provide electric
service to all customers within their power service area, and their
rates were regulated by state public utility commissions. In
exchange, they received exclusive service areas. To serve their
customers, IOUs could incur costs for building new generating plants
and operating the power system. Regulators generally allowed rates
to be set to guarantee IOUs full recovery of their prudently incurred
costs plus a regulated profit or rate of return.
However, the electric utility industry has been in the process of
transformation, with moves toward deregulation and competition being
major factors in this transformation. Deregulation will impact the
industry's three major segments: generation, dealing with the
production of electricity; transmission, involving moving bulk
electricity from the generation plant; and distribution, the process
of delivering the power to the retail consumer. An electric utility
usually controls all three segments within its service area.
The generation segment has been affected by improvements in
technology, which have reduced both the cost of generating
electricity as well as the size of generating facilities. Prior
preference for large-scale--often nuclear or coal-fired--power plants
has been supplanted by a preference for small-scale production
facilities, such as cogenerating plants\2
or small natural-gas-fired generation units, that can be brought
on-line more quickly and cheaply, with fewer regulatory impediments.
According to 1994 studies of utility best practices, primary actions
taken by utilities to satisfy demand are either adding small
gas-fired combustion units or purchasing power.\3 These sources are
less capital intensive and more flexible resources for satisfying
changing demand. Gas-fired plants can be built in relatively small
megawatt increments (for example, 50-150 megawatts), at perhaps
one-quarter of the cost of larger power plants. In 1995, almost half
of all new generating capacity starting commercial operation was
gas-fired, 99 percent of which was either gas turbine or combined
cycle units.
The generation segment of the industry has further been affected by
changes in legislation. The Public Utilities Regulatory Policies Act
of 1978 (PURPA) facilitated the creation of small (less than 80
megawatts of capacity) electricity generators that were exempt from
many state and federal regulations. Called "nonutility generators"
or "independent power producers" (IPPs),\4 these entities typically
use the newer technologies to generate power. The creation of IPPs
and their use of newer technologies have lowered the entry barriers
to electricity generation and permitted IPPs to build profitable
facilities. IPPs may pose a threat to more traditional utilities
because they can build generation facilities near large industrial or
municipal customers and generally may be able to generate power at a
lower cost than the established utility. The Electric Power Supply
Association\5 estimated that at the end of 1995, IPPs accounted for
about 9 to 10 percent of the total generating capacity in the United
States, directly competing with utility-owned capacity and placing
downward pressures on electricity rates.
The transmission segment of the industry has also undergone major
changes due to legislative changes. The Energy Policy Act of 1992
(EPAct) promoted increased wholesale competition by allowing
wholesale electricity customers, such as municipal distributors, to
purchase electricity from any supplier, even if that power must be
transmitted over lines owned by another utility. This transmission
of electricity across transmission lines of another utility is
referred to as wheeling of power. Under the act's provisions, the
Federal Energy Regulatory Commission (FERC)\6 can generally compel a
utility to transmit (wheel) electricity generated by another utility
into its service area for resale. Fees, which are regulated by FERC,
are paid to the transmitting utility for the use of its transmission
system.
On April 24, 1996, FERC issued Orders 888 and 889 to implement EPAct.
FERC Order 888 was key to the growth of wholesale (sales for resale)
competition because it provided a framework under which such
competition could flourish. In issuing its final rules, FERC
concluded that the rules would "remedy undue discrimination in
transmission services in interstate commerce and provide an orderly
and fair transition to competitive bulk power markets." At the time
the rules were issued, FERC estimated that the rules would result in
an annual cost savings of $3.8 billion to $5.4 billion. FERC also
expected other nonquantifiable benefits, including better use of
existing institutions and assets, new market mechanisms, technical
innovation, and less rate distortion.
As a result of PURPA and EPAct, and as provided for under FERC 888,
wholesale competition is becoming a reality today throughout the
country.\7 As a result, many IOUs have set up power marketing arms
(power marketers and power brokers)\8 that are buying and selling
excess power across the country. According to industry sources, the
number of power marketers registered in the United States increased
from 60 to 284 from January 1995 to February 1997--an increase of
over 370 percent.
With the advent of wholesale competition, pressure is growing to open
the distribution segment of the industry to allow retail competition
as well as to allow generating companies or utilities to sell
directly to final customers in the franchise area of a different
utility while paying regulated rates to use the utilities' existing
transmission and distribution lines. Just as wholesale wheeling
under EPAct opened competitors' transmission systems for wholesale
competition, retail competition would require open access to a
competitor's distribution system for the purpose of selling power to
individual retail customers.
Retail competition is taking shape on a state-by-state basis.
California became one of three states in 1996 to pass laws
deregulating electric utilities. Beginning January 1, 1998, all of
California's retail customers will be able to choose their
electricity suppliers. This change not only affects California's
current electricity suppliers, but also opens the door for other
companies hoping to sell power to California consumers. Regulatory
commissions in 44 states and the District of Columbia had adopted or
were evaluating deregulation alternatives as of June 30, 1996.
Issues relating to retail wheeling are also being addressed by the
Congress.
In many industries, competition has been shown to result in lower
costs. In the airline industry, we reported that average fare per
passenger mile was between 8 percent and 11 percent lower in 1994
than in 1979, while the overall quality of air service at airports
has increased.\9 As early as 1986, one study found that increased
competition arising from airline deregulation has resulted in a
savings for travelers of at least $6 billion annually in reduced
fares.\10 In the first 10 years after the telecommunications industry
was restructured, prices for long distance telephone services dropped
by 66 percent, while over the same period prices for regulated local
telephone service rose 13 percent. Similarly, since the natural gas
industry was restructured during the 1980s, prices for industrial gas
users dropped 52 percent, and residential rates dropped 10 percent
(although most residential customers still buy gas from regulated
local distribution companies).\11 Savings in the gas industry have
been placed at $90 billion over the last 10 years.\12
--------------------
\2 The cogeneration of power involves the use of steam, waste heat,
or resultant energy from a commercial or industrial plant or process
for generating electricity.
\3 1994 Electric Utility Outlook, Washington International Energy
Group (Washington, D.C., January 1994) and Issues and Trends Briefing
Paper: 18 Key Trends Affecting the Electric Utility Industry, Edison
Electric Institute (Washington, D.C., May 1994).
\4 IPPs are not considered utilities because they do not produce
power for a service area and do not engage in transmitting or
distributing power.
\5 The Electric Power Supply Association is a trade association
representing many nonutility generators of electricity and IPPs.
\6 FERC is an independent agency within the Department of Energy with
broad regulatory authority over the interstate transmission and sale
of wholesale electricity, natural gas, and oil.
\7 TVA, for the most part, is exempt from the wheeling provisions of
the Energy Policy Act of 1992 and therefore does not have to allow
competitors to use its transmission lines to sell power to TVA's
customers. This allows TVA's service area to remain insulated from
wholesale competition.
\8 Power marketers take title to electric energy before resale.
Power brokers, on the other hand, do not take title and are limited
to matching buyers with sellers.
\9 Airline Deregulation: Changes in Airfares, Service, and Safety at
Small, Medium-Sized, and Large Communities (GAO/RCED-96-79, April
1996).
\10 Steven Morrison and Clifford Winston, The Economic Effects of
Airline Deregulation, (Washington, DC.: The Brookings, 1986).
\11 "The Case for Retail Wheeling." Energy, Volume XX, Issue 5,
(1995), pp. 9-12. This article was excerpted from Peter C.
Christensen, Retail Wheeling: A Guide for End-users, (Tulsa,
Oklahoma: Penn Well Publishing Co., 1995).
\12 Patrick Crow, "Electric Restructuring," Oil & Gas Journal, Vol.
95, Issue 11 (March 17, 1997), p. 32.
STRANDED COSTS
------------------------------------------------------- Appendix I:1.1
In deregulating the electricity industry, several key issues need to
be resolved, including who will pay for stranded costs. Although
definitions vary, stranded costs cannot be recovered through rates
even though the utilities incurred those costs to serve their
customers with the understanding that regulatory commissions would
allow the costs to be recovered through electric rates. For example,
a utility may have built facilities or entered into long-term fuel or
purchased power supply contracts with the reasonable expectation that
its customers would renew their contracts and would pay their share
of long-term investments and other incurred costs. Accordingly, if
the customer obtains another power supplier or is no longer willing
to pay the full costs incurred to provide a service, the utility may
be unable to recover those costs and thus would have stranded costs.
Estimates of the U.S. industry's total stranded costs range from $10
billion to $500 billion, with $135 billion commonly cited as a
reasonable estimate. Although stranded costs are one of the most
contentious issues associated with deregulation, FERC has determined
that at the wholesale level, stranded costs should be paid by
electric customers desiring to exit a system built to serve them.
The following sections provide additional background information on
the federal entities involved in electricity generation,
transmission, and distribution that are discussed in this report.
THE RURAL UTILITIES SERVICE
--------------------------------------------------------- Appendix I:2
The U.S. Department of Agriculture (USDA) is the federal
government's principal provider of loans used to assist the nation's
rural areas in developing their utility infrastructure. Through the
Rural Utilities Service (RUS), USDA finances the construction,
improvement, and repair of electrical, telecommunications, and water
and waste disposal systems. RUS provides credit assistance through
direct loans and through repayment guarantees on loans made by other
lenders. Established by the Federal Crop Insurance Reform and the
Department of Agriculture Reorganization Act of 1994, RUS administers
the electricity and telecommunications programs that were operated by
the former Rural Electrification Administration (REA) and the water
and waste disposal programs that were operated by the former Rural
Development Administration (RDA). In this report we will only
discuss the electricity segment of RUS' overall utility loan
program.\13
Although operating somewhat like a commercial lender for rural
utilities, RUS is not required or intended to recover all of its
financing or other costs. RUS' primary function is to provide credit
assistance to aid in rural development. Interest charges to its
borrowers cover only a portion of the federal government's cost for
RUS' electricity loan programs.
--------------------
\13 The Rural Electrification Act of 1936, as amended (7 U.S.C. 901
et seq.), provides the basic statutory authority for the electricity
and telecommunications programs, including the authority for loans to
be made by the Federal Financing Bank.
RUS' ELECTRICITY LOAN
PROGRAMS
------------------------------------------------------- Appendix I:2.1
RUS makes direct loans primarily to construct and maintain
electricity distribution facilities that provide electricity to rural
users. RUS makes direct loans at below-market interest rates
according to law. For these loans, it receives annual appropriations
to cover the interest differential. It also receives an
appropriation to cover its administrative expenses. Loans from the
Federal Financing Bank (FFB) are made at Treasury's cost of money
plus one-eighth of 1 percent.
RUS electricity loans are made primarily to rural electric
cooperatives; more than 99 percent of the borrowers with electricity
loans are nonprofit cooperatives. These cooperatives are either
Generation and Transmission (G&T) cooperatives or distribution
cooperatives. A G&T cooperative is a nonprofit rural electric system
whose chief function is to sell electric power on a wholesale basis
to its owners, who consist of distribution cooperatives and other G&T
cooperatives. A distribution cooperative sells the electricity it
buys from a G&T cooperative to its owners, the retail customers. RUS
has 55 G&T borrowers (see figure I.1) and 782 distribution borrowers
located throughout the country with outstanding electricity loans.
Figure I.1: RUS G&T Borrowers
(See figure in printed
edition.)
Note: These RUS borrower identification codes designate the
respective locations of the 55 RUS G&T borrowers' headquarters.
Source: GAO analysis of data provided by RUS.
Some RUS loans are at below market interest rates. The following are
the types of loans provided in the electricity program:
-- Hardship rate loans: Direct loans with a 5 percent interest
rate. These loans, referred to as hardship rate loans, are made
to borrowers that serve financially distressed rural areas.
-- Municipal rate loans: Direct loans with interest rates that are
tied to an index of municipal borrowing rates. These loans have
a maximum interest rate of 7 percent when the borrower meets, at
the time of loan approval, either a consumer density test or
both an electricity rate disparity test and a consumer income
test. If these tests are not met, the interest rate may exceed
7 percent.
Consumer density test: The borrower's total electric system has to
have an average of less than 5.5 consumers per mile of line.
Rate disparity test: The borrower's average revenue per kilowatthour
sold has to be more than the average revenue per kilowatthour sold by
all electric utilities in the state in which the borrower provides
service.
Consumer income test: Either the average per capita income of the
residents receiving electric service from the borrower has to be less
than the average per capita income of residents of the state in which
the borrower provides service or the median household income of the
households receiving electric service from the borrower has to be
less than the median household income of the households in the state.
-- Direct FFB lending: RUS is required to make 100 percent loan
repayment guarantees for any loans made to rural utility
borrowers through FFB. FFB loans have an interest rate that is
the Treasury's cost of money plus one-eighth of 1 percent.
In addition to providing direct loans, RUS also guarantees repayment
of loans for rural utilities made by commercial banks--RUS guarantees
100 percent of loans from qualified lenders. However, RUS has not
guaranteed any loans from commercial banks in recent years because
all applicants have applied for loans made by the FFB, which offers
Treasury's interest rate plus one-eighth of 1 percent.
RUS' LOAN OBLIGATIONS
------------------------------------------------------- Appendix I:2.2
At September 30, 1996, RUS' portfolio included about $32.3 billion in
electricity-related loans and guarantees.\14 Most of the dollar
amount of the portfolio is made up of loans to the G&T cooperatives.
The principal outstanding on these G&T loans is approximately $22.5
billion, which is about 70 percent of the RUS electric loan
portfolio. Distribution borrowers make up the remaining 30 percent
of the electricity portfolio.
For a further discussion of RUS' financing and debt, see our report
entitled, Rural Development: Financial Condition of the Rural
Utilities Service's Loan Portfolio (GAO/RCED-97-82, April 11, 1997)
and appendixes V and VI of this report.
--------------------
\14 Collectively, RUS has a portfolio of $42.5 billion in outstanding
principal for utility loans including electricity,
telecommunications, and water and waste disposal.
POWER MARKETING ADMINISTRATIONS
--------------------------------------------------------- Appendix I:3
The federal government owns and operates numerous multipurpose dams,
many of which generate electric power. The power generated at these
facilities is marketed through five federal entities called power
marketing administrations (PMAs). The PMAs' mission is to market
power generated at federal hydroelectric dams at the lowest possible
rates to consumers, consistent with sound business principles. By
law, PMAs are required to give priority in the sale of federal power
to public power entities, such as public utility districts,
municipalities, and customer-owned cooperatives. These customers are
referred to as "preference customers."
The five PMAs--Southeastern Power Administration (Southeastern),
Southwestern Power Administration (Southwestern), Western Area Power
Administration (Western), Alaska Power Administration, and Bonneville
Power Administration (BPA)--are part of the Department of Energy
(DOE). Since the Alaska Power Administration is being sold to
nonfederal entities, it is excluded from our analysis in this report.
Additionally, throughout this report, we frequently discuss BPA
separately from the other three PMAs because its revenue is more than
twice as large as the other three PMAs combined and because it faces
different operating risks.
PMAs generally control and operate power transmission facilities\15
but do not control or operate the facilities (dams) that actually
generate electric power. These power generating facilities were
built and are operated by other federal agencies--most often by the
Department of the Interior's Bureau of Reclamation (Bureau) or the
U.S. Army Corps of Engineers (Corps). These agencies are referred
to as the operating agencies. The operating agencies constructed
these facilities as part of a larger effort in developing
multipurpose water projects that have functions other than power
generation, including flood control, irrigation, navigation, and
recreation. The projects must be operated in a way that balances
their authorized purposes--and, in many instances, power is not the
primary use. Responsibility for operating the facilities to serve
all of these multiple functions rests with the operating agencies.
PMAs sell electric power within 34 states--to all states except those
in the Northeast and upper Midwest (see figure I.2).\16 Each PMA has
its own specific geographic boundaries and system of projects from
which power is marketed.
Figure I.2: Service Areas for
Southeastern, Southwestern,
Western, and BPA
(See figure in printed
edition.)
Source: GAO analysis of data provided by the PMAs.
--------------------
\15 Southeastern has no transmission facilities.
\16 In addition to the areas shown on the map, the Alaska Power
Administration markets power in Alaska.
ROLE OF SOUTHEASTERN,
SOUTHWESTERN, AND WESTERN
------------------------------------------------------- Appendix I:3.1
Collectively, Southeastern, Southwestern, and Western sell power
produced at 102 facilities and market it in 30 states (see figure
I.2). In fiscal year 1995, they had total power revenue of almost $1
billion. The three PMAs differ substantially in size and revenue.
Western is the largest, accounting for more than 4 times the revenue
of either Southeastern or Southwestern. Southwestern and Western
have their own transmission facilities, while Southeastern relies
entirely on the transmission services of other utilities. Additional
specific information about the three PMAs is shown in table I.1.
Table I.1
Information on the Three PMAs
Revenue
Number of kWh sold (in
hydroelect Number of (billions) millions) Miles of
Year ric plants customers fiscal fiscal transmissi
created Sept. 1995 Sept. 1995 year 1995 year 1995 on lines
---------- -------- ---------- ---------- ---------- ---------- ----------
Southeaste 1950 23 296 6.8 $159 none
rn
Southweste 1943 24 95 7.7 114 1,380
rn
Western 1977\a 55 546 32.8 713 16,760
================================================================================
Total 102 937 47.3 $986 18,140
--------------------------------------------------------------------------------
\a In 1977, the DOE Organization Act established the Western Area
Power Administration and transferred power marketing responsibilities
and transmission assets previously managed by the Bureau of
Reclamation to Western. The act also transferred the other PMAs from
the Department of the Interior to DOE.
POWER-RELATED COSTS MUST
BE RECOVERED THROUGH
RATES
----------------------------------------------------- Appendix I:3.1.1
The Reclamation Project Act of 1939 and the Flood Control Act of 1944
generally require the recovery through power rates of costs of
producing and marketing federal hydropower. However, these acts do
not specify which costs are to be recovered, and as demonstrated in
our previous report,\17 the three PMAs do not recover all
power-related costs. The PMAs are required to recover the amount of
their own appropriations as well as the power-related expenditures
incurred by the operating agencies.
The three PMAs are generally funded through the annual appropriations
process.\18 The three PMAs receive annual appropriations to make both
capital expenditures, such as for PMA-controlled transmission
facilities, as well as operations and maintenance (O&M) expenditures.
PMAs generally pay for these expenditures by requesting Treasury to
cut checks on their respective appropriations accounts. Unlike most
other federal agencies, PMAs are required by law to recover through
their rates, and repay to the Treasury, the amount appropriated for
their power-related costs. The payments received from PMA customers
are deposited directly to the general fund at Treasury via a lockbox.
Ideally, over the course of a year, collections received by Treasury
will offset, or "repay," amounts appropriated to the PMAs for O&M
expenses, as well as an amortized amount of capital construction
costs. The PMAs monitor expenses and revenues to ensure that power
rates are sufficient to generate revenue to recover expenses.
The PMAs are required to recover not only their own costs, but also
the power-related expenditures incurred by the operating agencies.
The power-related portion of the operating agencies' expenditures
includes all capital costs and O&M expenses that are solely related
to the generation of power. In addition, a portion of the operating
agency's "joint costs" is allocated to the PMAs. These joint costs
are capital costs and O&M expenses related to both power production
and some of the water project's other purposes. The operating
agencies allocate the amount of joint costs that are power-related by
applying a percentage established for each multiple-purpose project.
PMAs set their rates to recover these costs from power revenues. The
total revenues of any project administered by a PMA are to be
sufficient to recover O&M expenses in the year incurred and to
recover the federal investment (appropriations) in generation and
transmission facilities (which we refer to as appropriated debt\19 ),
with interest, over a specified repayment period--generally 50 years
for assets used to generate power and 35 to 45 years for assets used
to transmit power.
--------------------
\17 Power Marketing Administrations: Cost Recovery, Financing, and
Comparison to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
1996).
\18 Some projects have been legislatively authorized to use revolving
funds to finance some types of expenditures. In addition, some
projects use nonfederal debt as a supplemental funding source.
\19 We call this appropriated debt because PMAs are required to repay
appropriations used for capital investments with interest. However,
these reimbursable appropriations are not technically considered
lending by Treasury.
PMAS' DEBT
----------------------------------------------------- Appendix I:3.1.2
As shown in figure I.3, the three PMAs are collectively responsible
for repaying about $7.2 billion of debt: $5.4 billion of
appropriated debt,\20 $1.6 billion of irrigation debt, and about $0.2
billion in nonfederal debt.\21 Under reclamation law, Western is
responsible for paying the costs of certain irrigation projects that
are judged to be beyond the ability of the irrigators to repay.\22 We
refer to these payments as irrigation debt. The nonfederal debt
refers to capital provided by Western's customers (primarily through
the issuance of bonds) to finance capital improvement projects.
Figure I.3: Composition of PMA
Debt
(See figure in printed
edition.)
Source: GAO analysis of data provided by the PMAs.
For a further discussion of the three PMAs' financing and debt, see
our report, Power Marketing Administrations: Cost Recovery,
Financing, and Comparison to Nonfederal Utilities (GAO/AIMD-96-145,
September 19, 1996), and appendix VII of this report.
--------------------
\20 One and one half billion dollars of the appropriated debt was
associated with Southeastern, $3.2 billion with Western, and $686
million with Southwestern. Audited figures for 1996 were unavailable
at the time of our fieldwork for Southeastern and Southwestern, so
September 30, 1995, balances are shown. According to the PMAs, these
balances did not change significantly between 1995 and 1996.
\21 All irrigation debt and nonfederal debt is attributable to
Western.
\22 Project authorizing legislation determines how the costs of
constructing reclamation projects are allocated and how repayment
responsibilities are assigned among the projects' beneficiaries.
Collectively, the federal reclamation statutes that are generally
applicable to all projects and the statutes authorizing individual
projects are referred to as reclamation law. In implementing
reclamation law, the Bureau of Reclamation and Western are guided by
implementing regulations, administrative decisions of the Secretary
of the Interior and the Secretary of Energy, respectively, and
applicable court cases.
ROLE OF BONNEVILLE POWER
ADMINISTRATION
------------------------------------------------------- Appendix I:3.2
BPA was created in 1937 to market electric power from the Bonneville
Dam and to construct facilities to transmit the power. It markets
electric power from the Federal Columbia River Power System, which
consists of 29 federally-owned hydroelectric projects located
primarily in the Columbia River Basin. BPA's primary customer
service area, as shown in figure I.2, is a 300,000 square mile area
of the Pacific Northwest, comprised of Oregon, Washington, Idaho,
western Montana, and small portions of California, Nevada, Utah, and
Wyoming. BPA sells primarily wholesale power from the dams and other
generating plants to public and private utilities and direct service
industries. By law, BPA gives preference to public utilities in
sales of power and sells only excess power outside the Pacific
Northwest. BPA builds, owns, and operates transmission lines that
comprise 75 percent of the Northwest's high-voltage transmission
capacity. (See table I.2.)
Table I.2
Information on BPA
Revenue
Number of kWh sold (in
hydroelect Number of (billions) millions) Miles of
Year ric plants customers fiscal fiscal transmissi
created Sept. 1995 Sept. 1995 year 1995 year 1995 on lines
---------- -------- ---------- ---------- ---------- ---------- ----------
BPA 1937 29\a 193 80.4 $2,182 15,012
--------------------------------------------------------------------------------
\a BPA has entered into nonfederal debt agreements to acquire all or
part of the generating capacity of power projects of other entities,
including four nuclear plants and some small hydroelectric projects.
The Federal Columbia River Power System provides roughly half the
power used in the Pacific Northwest. BPA, the Corps, and the Bureau
coordinate system operation with the many public and privately owned
utilities that own dams on the river system. Over the years,
Congress has expanded BPA's mission to include conservation and
renewable resource development, rate relief for specified residential
and small farm power users, and specific mandates for fish and
wildlife protection and funding.
BPA'S POWER PROGRAM IS TO
BE SELF-SUPPORTING
----------------------------------------------------- Appendix I:3.2.1
Unlike the other PMAs, BPA no longer receives an annual
appropriation. The Federal Columbia River Transmission System Act of
1974 placed BPA on a self-financing basis--so that its operating
expenses are paid for by operating revenues (power and transmission
sales). Funds received from customers are paid to BPA, which then
deposits the receipts into a special BPA fund at Treasury.
Expenditures for BPA are then paid for out of that special BPA fund
at Treasury. To provide for capital expenditures, BPA does have
authority to borrow from the Treasury. Treasury bond borrowing
authority is capped at $3.75 billion ($2.5 billion for transmission
and other capital investments and $1.25 billion for conservation and
renewable energy investments). The agency is required to set its
rates for power and transmission sales at levels that generate
revenues sufficient to cover annual expenses and pay back previously
appropriated funds. BPA is required to make an annual payment to
Treasury that includes debt servicing costs on appropriated debt and
Treasury bonds. Similar to the three PMAs discussed previously, BPA
is also required to recover and repay to the Treasury the operating
agencies' power-related capital and operating expenses. Unlike the
other PMAs, BPA has a legislative mandate that requires it, within
certain limits, to provide sufficient firm power to meet the needs of
its primary regional customers.
BPA'S DEBT
----------------------------------------------------- Appendix I:3.2.2
As shown in figure I.4, BPA's total debt as of September 30, 1996,
was $17.2 billion, including $6.8 billion for appropriated debt, $2.5
billion for Treasury bonds, $7.1 billion for nonfederal debt, and
$0.8 billion in irrigation debt.
Figure I.4: Composition of
BPA's Total Debt as of
September 30, 1996
(See figure in printed
edition.)
Source: GAO analysis of data provided by BPA.
In the late 1960s, BPA and the region's utilities forecasted that
electrical demand would triple between 1970 and 1990 and concluded
that the region needed to supplement its hydroelectric capacity with
new forms of generation. Subsequently, BPA entered into nonfederal
financing agreements to acquire all or part of the output of four
nuclear power plants constructed, owned, and to be operated by other
entities. As part of these agreements, BPA was required to pay for
the annual project costs, including debt service, in amounts ranging
from 30 to 100 percent of total costs incurred. Later, a variety of
events, including construction cost overruns and overly optimistic
estimates of electricity demand, made it clear that some of these
plants would not be economical to complete or operate. Accordingly,
construction was halted on two of these nuclear plants and they were
not completed. In addition, one previously operating plant has been
shut down permanently. As a result, BPA is responsible for
approximately $4.2 billion in nonfederal debt associated with three
nonoperating nuclear plants and an additional $2.5 billion in
nonfederal debt associated with the one operating nuclear plant.\23
For a further discussion of BPA's financing and debt, see our report,
Bonneville Power Administration: Borrowing Practices and Financial
Condition (GAO/AIMD-94-67BR, April 19, 1994), and appendix VIII of
this report.
--------------------
\23 The nonfederal debt also consists of $321 million invested in
small hydroelectric projects and conservation measures.
THE TENNESSEE VALLEY AUTHORITY
--------------------------------------------------------- Appendix I:4
The Tennessee Valley Authority (TVA) is a multipurpose, independent
federal corporation established by the Tennessee Valley Authority Act
of 1933.\24 The act established TVA to improve the quality of life in
the Tennessee River Valley by improving navigation, promoting
regional agricultural and economic development, and controlling the
flood waters of the Tennessee River. To those ends, TVA erected dams
and hydroelectric power facilities on the Tennessee River and its
tributaries. To meet the need for more electric power during World
War II, TVA expanded beyond hydropower, building coal-fired power
plants. In the 1960s, TVA decided to add nuclear generating units to
its power system to meet projected heavy growth in electricity
demands.\25
Today, TVA's other roles have been eclipsed by its electricity
program. TVA has become the nation's largest electric power
generator, with a dependable capacity in service of over 28,000
megawatts and 16,021 employees as of September 30, 1996. TVA sells
power in seven states--Alabama, Georgia, Kentucky, Mississippi, North
Carolina, Tennessee, and Virginia--as illustrated in figure I.5.
Additional specific information about TVA is shown in table I.3.
Figure I.5: TVA Service Area
(See figure in printed
edition.)
Source: Developed by GAO from data provided by TVA.
Table I.3
Information on TVA
Revenue
Number of kWh sold (in
hydroelect Number of (billions) millions) Miles of
Year ric plants customers fiscal fiscal transmissi
created Sept. 1996 Sept. 1996 year 1996 year 1996 on lines
---------- -------- ---------- ---------- ---------- ---------- ----------
TVA 1933 29\a \160\b 140.6 $5,693\c 17,000
--------------------------------------------------------------------------------
\a These 29 plants have 109 generating units. TVA also has 4
additional units at a pumped storage plant, 59 units at 11 coal-fired
plants, 48 combustion turbines at 4 sites, and 5 operating nuclear
units at 3 plants.
\b TVA sells primarily wholesale power. As of September 30, 1996,
TVA's 160 wholesale distributors--municipal and cooperatives--in turn
sell power on a retail basis to nearly 8 million customers. TVA also
has about 67 directly served large industrial customers and federal
agencies.
\c Total operating revenues from power programs.
--------------------
\24 The TVA Act as amended (16 U.S.C. 831 et seq.) provides the
basic statutory authority for TVA.
\25 For a more detailed discussion of TVA's nuclear program, see
Tennessee Valley Authority: Financial Problems Raise Questions About
Long-term Viability (GAO/AIMD/RCED-95-134, August 17, 1995).
LEGISLATION AFFECTING TVA
------------------------------------------------------- Appendix I:4.1
TVA's authorizing legislation allows it to operate with a relatively
high degree of independence. The TVA Act of 1933 did not subject TVA
to the regulatory and oversight requirements that must be satisfied
by commercial electric utilities. As opposed to the regulatory
environment faced by other utilities, all authority to run and
operate TVA is vested in TVA's three-member board of directors,
including the sole authority to set wholesale electric power rates
and approve the retail rates charged by TVA's distributors.\26 The
three board members are full-time employees of TVA. They are
appointed by the President, with the advice and consent of the
Senate, and serve 9-year overlapping terms of office. The President
designates one member as the chairman.
In 1959, the Congress amended the TVA Act in an attempt to protect
surrounding utilities from competition with TVA because it was a
low-cost federal utility. By establishing what is commonly referred
to as the TVA "fence," the 1959 amendments prohibited TVA--with some
exceptions--from entering into contracts to sell power outside the
service area TVA and its distributors were serving on July 1, 1957.
TVA was allowed to continue to sell power to certain other utilities
outside of its service area if the power is surplus to the
requirements of TVA's own customers. TVA can also buy power when
needed.
Because TVA is, for the most part, legally prohibited from making
sales outside of its service area, the Energy Policy Act of 1992
exempted TVA from its wheeling requirements.\27 This exemption
prevents competitors from using TVA's transmission system to sell to
customers inside TVA's service area.\28 TVA is therefore generally
insulated from wholesale competition and remains in a position
similar to a regulated utility monopoly.
--------------------
\26 TVA is subject to some other regulatory actions, such as the
Nuclear Regulatory Commission's (NRC) role in licensing and
inspecting nuclear facilities and the Environmental Protection
Agency's environmental regulations.
\27 Section 722 of the Energy Policy Act of 1992, 106 Stat 2919.
\28 However, the exemption specifically did not cover the Bristol
Virginia Utilities Board.
TVA'S POWER PROGRAMS ARE TO
BE SELF-SUPPORTING
------------------------------------------------------- Appendix I:4.2
As mentioned, TVA's programs are divided into two types of
activities--the nonpower programs and the power programs. The
nonpower programs, such as water resources, navigation, and flood
control, are primarily funded through federal appropriations and user
fees. These programs received about $109 million in funding in
fiscal year 1996 and are operated primarily within the 41,000 square
mile Tennessee River watershed.\29 Since the 1959 amendments to the
TVA Act, TVA's power program does not receive any federal
appropriations and is required to be self-supporting, so that their
operating expenses are paid for by operating revenues (power sales).
TVA's power program generated about $5.7 billion in fiscal year 1996
revenues, with about $5.0 billion (88 percent) of this amount coming
from the 160 wholesale distributors. The other 12 percent primarily
came from sales to directly served industries and federal agencies.
--------------------
\29 TVA's nonpower programs were not included in the scope of this
report.
TVA'S DEBT
------------------------------------------------------- Appendix I:4.3
Although TVA's power programs are required to be self-funded, TVA is
authorized to use debt financing to pay for capital improvements in
excess of internally generated funds. In 1959, TVA was authorized to
borrow by issuing bonds and notes with a debt limit set by the
Congress at $750 million. Since then, TVA's debt limit has been
increased four times by the Congress and is currently capped at $30
billion. As of September 30, 1996, TVA had accumulated almost $28
billion in debt: $3.2 billion in direct federal borrowing from FFB
and $24.1 billion in publicly issued TVA debt (which is not
explicitly guaranteed by the federal government). In addition, TVA
is also required to repay funds appropriated to it prior to becoming
self-funding in 1959--the outstanding balance was approximately $600
million as of September 30, 1996. Although we refer to this as
appropriated debt, this amount does not count toward TVA's $30
billion debt cap.\30
Figure I.6: Composition of TVA
Debt as of September 30, 1996
(See figure in printed
edition.)
Source: GAO analysis of data provided by TVA.
For a more detailed discussion of TVA's financing and debt, see our
report, Tennessee Valley Authority: Financial Problems Raise
Questions About Long-term Viability (GAO/AIMD/RCED-95-134, August 17,
1995), and appendix IX of this report.
--------------------
\30 TVA refers to this as "appropriation investment" and treats it as
a proprietary capital account for financial statement purposes.
OBJECTIVES, SCOPE, AND METHODOLOGY
========================================================== Appendix II
The Chairman, House Committee on the Budget, and the Chairman,
Subcommittee on Water and Power Resources, House Committee on
Resources, asked us to review several issues relating to federal
electricity finances. The specific objectives of our review were to
(1) estimate the federal government's fiscal year 1996 net recurring
cost and, where possible, fiscal years 1992 through 1996 cumulative
net recurring cost\1 from ongoing operations of electricity-related
activities at the Rural Utilities Service (RUS), the Department of
Energy's (DOE) power marketing administrations\2 (PMAs), and the
Tennessee Valley Authority (TVA) (see appendixes IV and V) and (2)
assess the likelihood of future losses beyond the net recurring costs
to the federal government from the electricity-related activities of
these entities (see appendixes VI, VII, VIII, and IX).
As agreed with the requesters, we did not (1) estimate the forgone
revenue for federal, state, or local governments resulting from the
tax exempt status of the RUS borrowers, the PMAs, or TVA, (2)
estimate the forgone revenue for federal and state governments
resulting from tax-exempt debt instruments issued by TVA or related
to Western or BPA nonfederal debt, (3) assess the reasonableness of
the methodologies used by the operating agencies to allocate
power-related costs to the PMAs for recovery, or (4) quantify the
amount of potential future losses to the federal government.
As also agreed with the requesters, we did not include the following
in our review: the Alaska Power Administration, the Federal Energy
Regulatory Commission (FERC), the nonpower aspects of RUS and TVA,
and the Nuclear Regulatory Commission (NRC). As agreed, we estimated
the net cost to the federal government on the accrual basis of
accounting.\3
These net costs either already have had or will have an impact on the
federal budget. In addition, it was beyond the scope of our review
to evaluate the public benefits provided by the PMAs, RUS, and TVA to
their respective regions.
The following sections detail the methodologies used in our analyses
and additional restrictions on the scope of our work.
--------------------
\1 Estimates of cumulative net costs for fiscal years 1992 through
1996 are stated in constant 1996 dollars.
\2 We reviewed the electricity related activities of four PMAs:
Bonneville Power Administration (BPA), Southeastern Power
Administration (Southeastern), Southwestern Power Administration
(Southwestern), and Western Area Power Administration (Western).
Because BPA faces different operating risks and its annual revenue is
more than 2 times larger than the other three PMAs combined, we
frequently discuss BPA separately. Since legislation has been
enacted to sell the Alaska Power Administration to nonfederal
entities, it was excluded from our review.
\3 The accrual basis of accounting recognizes the impact of revenue
and expense transactions on the financial statements in the time
period when they occur.
FEDERAL GOVERNMENT'S DIRECT AND
INDIRECT FINANCIAL INVOLVEMENT
IN THE ELECTRICITY-RELATED
ACTIVITIES AT RUS, THE PMAS,
AND TVA
-------------------------------------------------------- Appendix II:1
Net recurring costs and exposure to additional financial losses
result from the federal government's direct and indirect financial
involvement in the electricity-related activities of these entities.
For this report, we defined direct involvement in electricity
activities as loans or loan guarantees made by the federal government
directly to RUS borrowers and appropriated debt\4 owed by the PMAs or
TVA. As of September 30, 1996, the federal government had over $53
billion of direct financial involvement. The federal government
would have financial losses from its direct involvement if the RUS
borrowers or the federal entity were unable to repay debt owed to the
federal government.
For this report, we defined indirect involvement as nonfederal
financing. As of September 30, 1996, the federal government had
indirect financial involvement of over $31 billion--primarily
nonfederal financing of BPA\5 and bonds issued by TVA. Although
BPA's nonfederal financing and TVA bonds are not explicitly
guaranteed by the federal government, the financial community
generally views them as having an implicit federal guarantee. The
federal government would have losses from its indirect involvement if
it incurred unreimbursed costs as a result of actions it took to
prevent default on nonfederal debt service payments or breach of
contract by the federal entity on nonfederal financing.
--------------------
\4 We call this appropriated debt because the PMAs are required to
recover from ratepayers, with interest, appropriations used for
capital investments, including funds appropriated to construct, as
well as to operate and maintain, power-related facilities. However,
these amounts are not technically considered lending by Treasury.
\5 BPA calls this "nonfederal project financing." BPA used its
contracting authority to acquire all or part of the generating
capability of power projects or other entities. Under these
agreements, BPA contracts to pay all or part of the annual project
budgets, including debt service, whether or not the projects are
completed. BPA does not have the authority to borrow from nonfederal
sources. See appendix VIII for additional discussion. For Western,
nonfederal financing refers to capital provided by its customers
(primarily through the issuance of bonds) to finance capital
improvement projects.
ASSESSING THE NET COST FROM
ONGOING OPERATIONS OF
ELECTRICITY-RELATED ACTIVITIES
AT RUS, THE PMAS, AND TVA
-------------------------------------------------------- Appendix II:2
In order to assess the federal government's net recurring cost from
ongoing operations of electricity-related activities, we defined the
full cost of the PMAs and TVA producing and marketing federal power
and of RUS providing loans and loan guarantees to its borrowers based
on our review of applicable federal guidance and industry practice.
Then, we determined whether, for each entity, (1) there is a net
financing cost, (2) pension and postretirement health benefits were
fully recovered, and (3) other costs were fully recovered.
Most of the data used in our analysis was obtained from audited
financial statements. Independent public accounting firms or Offices
of Inspector General audited the financial statements of RUS, the
PMAs, and TVA in accordance with private sector and government
auditing standards. On the basis of their audits, the firms or
Offices of Inspector General issued opinions on the fairness of the
agency's financial statements and the adequacy of the agency's
internal controls and compliance with laws and regulations.
The 1996 financial operations of RUS were audited by the Department
of Agriculture's (USDA) Office of Inspector General. RUS is a
component of USDA's rural development mission area and is included as
part of the rural development's consolidated financial statements.
USDA's Office of Inspector General issued a qualified opinion on the
1996 financial statements for the rural development mission area
because of weaknesses in the estimation and reestimation of loan
subsidy costs related to the Federal Credit Reform Act of 1990.\6
However, the qualification did not affect the data that we needed to
conduct our analysis of net financing costs. RUS' fiscal years 1992
through 1995 financial statements were audited by Urbach Kahn &
Werlin (UKW). UKW issued an unqualified opinion on RUS' financial
statements for 1992 through 1995, indicating that the financial
statements were fairly stated in all material respects.
BPA's financial statements are audited by Price Waterhouse. Price
Waterhouse issued an unqualified opinion on BPA's financial
statements for fiscal years 1992 through 1996, indicating that the
financial statements were fairly stated in all material respects.
Western's fiscal years 1992 through 1996 financial statements and
Southeastern's and Southwestern's fiscal years 1994 and 1995
financial statements were audited by KPMG Peat Marwick (KPMG). KPMG
was hired by the DOE Inspector General to perform the audits of these
PMAs. KPMG issued an unqualified opinion on Western's fiscal years
1992 through 1996 financial statements and on Southeastern's and
Southwestern's fiscal years 1994 and 1995 financial statements.
Audited financial statements for 1996 were not available for
Southeastern and Southwestern; therefore, we used 1995 audited
financial statements. Southeastern's fiscal years 1992 and 1993
financial statements were audited by Deloitte & Touche, which issued
an unqualified opinion on them. Southwestern's fiscal years 1992 and
1993 financial statements were audited by RJ Miranda & Company and
Price Waterhouse, which issued unqualified opinions on them.
The financial statements of TVA are audited by Coopers & Lybrand,
which issued an unqualified opinion on TVA's fiscal years 1992
through 1996 financial statements, indicating that the financial
statements were fairly stated in all material respects. However, in
1994 and 1995, the opinions also included a "matter of emphasis"
relating to TVA's deferred nuclear assets.
While it was not within the scope of our work to assess the overall
quality of the auditors' work, we reviewed selected 1996 audit work
papers (1995 audit work papers for Southeastern, Southwestern, and
Western) and management letters to obtain background information.
Throughout our report, where possible, we used audited numbers from
each entity's 1996 and prior years' annual reports. In addition,
where possible, we used audited numbers from the 1996 and prior
years' annual reports of IOUs and RUS generation & transmission
cooperatives.
We interviewed numerous officials at RUS, the PMAs, the operating
agencies, and TVA. We provided questions to each of the respective
entities relating to cost recovery and other matters addressed in our
report. We analyzed data provided to us by the entities to determine
which costs are and are not fully recovered from borrowers or
ratepayers. The net costs identified in this report focus on the
material items we found in reviewing the data sources described in
this appendix. There could be additional net costs that did not come
to our attention during this review.
--------------------
\6 RUS is required to budget for and report on its loans and
guarantees in accordance with the requirements of the Federal Credit
Reform Act of 1990 and Statement of Federal Financial Accounting
Standards (SFFAS) No. 2, Accounting for Direct Loans and Loan
Guarantees. The two key principles of credit reform contained in the
Federal Credit Reform Act center on the (1) definition of cost in
terms of the present value of the estimated net cash flow over the
life of a credit instrument and (2) inclusion in the budget of the
estimated costs of credit programs before direct or guaranteed loans
are made or modified. The budget and accounting requirements under
credit reform were effective for loans and guarantees made after
October 1, 1991. The majority of RUS electricity loans and
guarantees were made prior to October 1, 1991 and therefore are not
reported under credit reform requirements. Additionally, because the
credit reform estimates are not reliable at RUS, we chose to use
actual costs incurred rather than any credit reform cost estimates
for our analysis.
DEFINING THE FULL COST OF
PRODUCING AND MARKETING
FEDERAL POWER AND OF
PROVIDING LOANS AND LOAN
GUARANTEES TO BORROWERS
------------------------------------------------------ Appendix II:2.1
To define the full costs associated with producing and marketing
federal power and of providing loans and loan guarantees to
borrowers, we referred to Office of Management and Budget (OMB)
Circular A-25, User Fees, which provides guidance for use in setting
fees to recover the full costs of providing goods and services. The
circular defines full cost as all direct and indirect costs of
providing goods and services and is consistent with guidance of full
cost reporting contained in Statement of Federal Financial Accounting
Standards (SFFAS) No. 4, Managerial Cost Accounting Concepts and
Standards for the Federal Government and industry practice. In
accordance with the criteria from OMB Circular A-25,
SFFAS No. 4, and industry practice, the full cost of producing and
marketing power or providing loans and loan guarantees is the sum of
all direct and indirect costs incurred by RUS, the PMAs, and TVA and
the costs incurred by any other agencies to support the operations of
RUS, the PMAs, and TVA.
ASSESSING NET FINANCING
COSTS
------------------------------------------------------ Appendix II:2.2
For this report, we defined the net financing cost to the Treasury as
the difference between Treasury's borrowing cost or interest expense
and the interest income received from RUS borrowers, the PMAs, and
TVA. Our objective was to determine what the net cash flow was to
the federal government from lending transactions with its
electricity-related activities.\7 Treasury's borrowing cost is
particularly relevant because the federal government has had debt
outstanding since before 1940--before the oldest RUS borrowers and
PMA or TVA debt still outstanding--and has had a deficit every year
since 1969. Thus, it is reasonable to assume that the federal
government has had to issue debt to extend financing to RUS
borrowers, the PMAs, and TVA.
Our basic methodology was to determine whether the federal government
received a return sufficient to cover its borrowing costs and, if
not, to estimate the net financing cost. RUS, the PMAs, and TVA had
several forms of federal debt outstanding at September 30, 1996.
Each of these forms of federal debt had different terms and thus
required us to apply different variations of our basic methodology in
assessing whether there was a net financing cost to the federal
government and, if so, measuring the magnitude of this net cost. The
following are the specific methodologies used for RUS financing and
PMA appropriated debt, TVA's appropriated debt, TVA's Federal
Financing Bank (FFB) debt, and BPA's Treasury bonds.
--------------------
\7 If our objective had been to calculate an economic financing
subsidy rather than the net cash flow to Treasury, consideration of
other forms of subsidy would have been necessary. For example, our
calculation of net financing cost excludes the impact that the risk
of federal hydropower projects might have had on the PMAs' interest
rates if they had been financed in the private market rather than
through Treasury. Our methodology also does not consider the
difference between Treasury debt being compounded semiannually versus
PMA and RUS debt being compounded annually.
RUS FINANCING AND PMA
APPROPRIATED DEBT
------------------------------------------------------ Appendix II:2.3
We assessed the net financing cost of the RUS loan portfolio and PMA
appropriated debt using substantially the same methodology, which we
refer to as the portfolio methodology. Under this methodology, we
obtained the amount of interest income paid to the federal government
by RUS borrowers and the PMAs from the audited 1996 financial
statements.\8 Since Treasury does not match its borrowing with loans
made to RUS borrowers or the PMAs' appropriated debt financing and
does not specifically price the debt based on its terms, the federal
government's interest expense associated with the funds provided to
the RUS borrowers and PMAs must be estimated. PMA appropriated debt
and RUS borrower loans have fixed interest rates over terms of up to
35 years for RUS borrowers and 50 years for PMAs. Treasury does not
have the ability to call\9 PMA appropriated debt or RUS borrower
loans.
To estimate the federal government's interest expense, we used the
weighted average interest rate on Treasury's entire outstanding bond
portfolio because it best reflects its cost of long-term borrowing.
The bond portfolio's average interest rate includes bonds with
varying maturities up to 30 years. Treasury's bond portfolio average
interest rate of 9 percent was obtained from the Monthly Statement of
the Public Debt of the United States as of September 30, 1996. This
document is published by the Bureau of Public Debt, Department of
Treasury. Specific calculations of interest expense using the 9
percent Treasury cost of funds are discussed below.
Although both PMA appropriated debt and RUS borrower loans are long
term with fixed interest rates, application of the portfolio
methodology varies to some extent, as described below.
--------------------
\8 Because audited fiscal year 1996 data were not available for
Southeastern and Southwestern at the time of our fieldwork, we used
fiscal year 1995 appropriated debt and weighted average interest
rates. According to the PMAs, these balances did not significantly
change from 1995 to 1996. We then estimated fiscal year 1996 net
financing cost using the 1996 Treasury average interest rate.
\9 Call refers to the ability of the lender to require the borrower
to pay back the debt before its maturity date.
RUS FINANCING
---------------------------------------------------- Appendix II:2.3.1
There are four main aspects of the net financing cost to Treasury of
the RUS debt, although not all RUS debt has each of these elements.
The first is the difference between the RUS borrower's interest rate
and the interest rate on the closest match of Treasury borrowing in
terms of maturity at the time the loan was made (interest rate
spread). The second is that financially troubled RUS borrowers have
missed significant scheduled loan payments (delinquent interest
payments). The third is that RUS borrower loans have maturities of
up to 35 years, which is beyond the maximum maturity of Treasury
bonds. Thus, if RUS borrowers do not repay their loans within 30
years, Treasury would have to refinance its corresponding debt
(maturity differential). The fourth is that Treasury's borrowing
practices are inflexible in that it is generally unable to refinance
or prepay outstanding debt in times of falling interest rates
(Treasury borrowing practices).
In order to calculate the net financing costs to Treasury under the
portfolio method, we obtained the federal government's annual
interest income from RUS borrowers from supporting financial
statement documentation. RUS does not recognize interest income on
delinquent loans, which reduces its interest income. Interest income
on delinquent loans is recorded when it is received.
To calculate the federal government's annual interest expense, we
added the estimated interest expense paid by Treasury to bondholders
to finance RUS federal debt and the interest expense paid to private
lenders. Interest from government borrowing was estimated by
multiplying the amount of RUS federal government borrowing
outstanding by the average interest rate Treasury was paying on its
portfolio of bonds outstanding at the end of fiscal year 1996--9
percent. For interest expense to private lenders, we obtained the
actual amounts paid to the lenders from supporting financial
statement documentation and other supporting documents. The sum of
interest expense on federal and private debt yields an estimate of
the amount of annual interest expense Treasury must pay on the RUS
loan portfolio. We obtained the total RUS debt owed to Treasury and
FFB from the final trial ledger balance. Finally, we subtracted the
interest income received by Treasury from RUS borrowers from the
estimated interest expense paid by Treasury on the RUS loan
portfolio. The difference between these two amounts constitutes the
net financing costs to Treasury. See appendix V for a detailed
calculation of the RUS net financing cost.
PMA APPROPRIATED DEBT
---------------------------------------------------- Appendix II:2.3.2
There are four main aspects of the net financing cost to the federal
government from the PMAs' appropriated debt, although not all PMA
debt has each of these elements. The first is the difference between
the PMA borrowing rate and the interest rate on the closest match of
Treasury borrowing in terms of maturity at the time of the
appropriation (interest rate spread). The second is the PMAs'
ability to repay the highest interest-bearing appropriated debt first
(prepayment option). The third is that Treasury's borrowing
practices are inflexible in that it is generally unable to refinance
or prepay outstanding debt in times of falling interest rates
(Treasury borrowing practices). This inflexibility is part of the
reason for Treasury's relatively high cost of funds--9.0 percent on
its outstanding portfolio of bonds as of September 30, 1996. The
fourth is that PMA appropriated debt has maturities of up to 50
years, which is beyond the maximum maturity of Treasury bonds. Thus,
if appropriated debt is not repaid within 30 years, Treasury would
have to refinance its corresponding debt (maturity differential).
In order to calculate the net financing costs to the Treasury under
the portfolio method, we obtained the federal government's annual
interest income from the PMAs by multiplying the amount of PMA
appropriated debt outstanding at September 30, 1996, by the weighted
average interest rate paid by the PMAs. Appropriated debt and the
weighted average interest rate paid by the PMAs were taken from the
1996 audited financial statements.\10 We reconciled these figures to
interest expense and capitalized interest reported in the PMAs'
audited financial statements.
To calculate interest expense for the federal government, we
multiplied the amount of PMA appropriated debt outstanding by the
average interest rate Treasury was paying on its portfolio of bonds
outstanding at the end of fiscal year 1996--9 percent--which yields
an estimate of the amount of interest expense Treasury must pay on
the PMAs' outstanding appropriated debt. The difference between the
federal government's interest income and interest expense represents
the net financing cost. For a further discussion of PMA financing,
see Power Marketing Administrations: Cost Recovery, Financing, and
Comparisons to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
1996).
To assess the effects of the restructuring of BPA's appropriated
debt, we reviewed the provisions of the BPA Appropriations
Refinancing Act and examined the mechanics of how the restructuring
was to take place under the act. We also discussed the restructuring
with BPA officials and reviewed BPA documents regarding the
implementation of the act and its effects on BPA's appropriated debt
and interest expense. We did not perform any calculations to
determine the accuracy of the position taken by BPA that the present
value of the appropriated debt after the restructuring is identical
to the present value of this debt prior to the restructuring. We
also did not review the impact of the debt restructuring on the
federal budget.
--------------------
\10 As previously discussed, we used 1995 data for Southeastern and
Southwestern because their 1996 audited financial statements were not
available.
LOAN-BY-LOAN METHODOLOGY
---------------------------------------------------- Appendix II:2.3.3
The net financing cost for RUS financing and PMA appropriated debt in
our report is calculated using the portfolio methodology. We also
calculated the net financing costs to the Treasury under an
alternative methodology we refer to as the loan-by-loan methodology.
This methodology attempts to match the RUS federal debt and the
appropriated debt of two of the PMAs--Southwestern and BPA--with
Treasury borrowing. The loan-by-loan methodology assumes that in
order to provide up to 50-year financing for a PMA project and up to
35-year financing for RUS debt, the Treasury must borrow an
equivalent amount via the sale of long-term bonds. Because Treasury
does not borrow for more than 30-year terms, this methodology also
assumes that when necessary, Treasury must refinance each borrowing
to extend the financing to the PMAs or RUS borrowers for the
remainder of the terms of the debt.
We performed this analysis to estimate the 1996 net financing cost
for Southwestern, BPA, and RUS. We found that the loan-by-loan
methodology resulted in a larger net financing cost for Southwestern
and BPA, and the same for RUS. Thus, the portfolio methodology is
generally a more conservative estimate of the magnitude of the net
financing cost for this debt. However, the primary reason we did not
use the loan-by-loan methodology to calculate net financing costs is
that Treasury does not match its borrowing with RUS financing or PMA
appropriated debt. Thus the loan-by-loan methodology is less
realistic than the portfolio methodology in estimating what the
actual net cost of PMA appropriated debt and RUS financing is to the
federal government.
OTHER FINANCING FOR TVA AND
BPA
------------------------------------------------------ Appendix II:2.4
TVA had outstanding appropriated debt\11 and FFB debt and BPA had
outstanding Treasury bonds at September 30, 1996. Unlike the PMA
appropriated debt and RUS financing, these financing arrangements
were designed so that Treasury would recover its cost of providing
the funds to TVA and BPA. To determine whether TVA appropriated
debt, TVA FFB debt, and BPA Treasury bonds resulted in a net
financing cost to the federal government, we assessed whether the
terms of each type of debt resulted in recovery of a reasonable
approximation of the federal government's cost of providing the
funds.
--------------------
\11 We call this appropriated debt because TVA is required to repay
all but $258.3 million of the appropriations that were used for
capital investments, plus interest. However, these reimbursable
appropriations are not technically considered lending by the
Treasury. In addition, TVA refers to this debt as appropriation
investment and considers it to be equity. Accordingly, TVA considers
annual payments as a reduction of equity capital and the annual
return as a dividend. We refer to the annual payments as principal
payments, and the annual return as interest expense.
TVA'S APPROPRIATED DEBT
------------------------------------------------------ Appendix II:2.5
As of September 30, 1996, TVA had $608 million of appropriated debt
outstanding that represented appropriations received by TVA to
construct its hydroelectric dams, fossil plants, transmission system,
and other general assets of the power program. This debt was
incurred from the inception of TVA in 1933 through 1959. When the
TVA Act was amended in 1959 to give TVA the authority to
"self-finance," TVA was required to begin making annual payments from
net power proceeds for principal on this debt, plus a market rate of
return (interest expense) to Treasury on the unpaid balance. TVA's
appropriated debt has substantially different terms than the PMAs'
appropriated debt. First, annual principal payments (currently $20
million) are required for the more than 50 years from 1959 until TVA
pays down the balance to $258.3 million. Once the balance is $258.3
million, TVA is required to continue to pay annual interest expense
on this balance. Second, the interest rate on TVA's appropriated
debt is variable and is reset each year. The interest rate used is
the rate on Treasury's total marketable public obligations
outstanding at the beginning of the year. Thus, unlike PMA
appropriated debt, which has a fixed interest rate for up to 50
years, TVA's appropriated debt is similar to a variable interest rate
loan. As a result, TVA's interest payments to Treasury have and
should continue to approximate Treasury's total cost of funds over
time.
Because the repayment terms of this debt include a 1-year variable
interest rate, which is a short-term debt feature, and a repayment
term of more than 50 years, which is characteristic of long-term
debt, we concluded that use of Treasury's average interest rate for
all marketable public obligations results in a reasonable return and
no net cost to the federal government.
TVA'S FEDERAL FINANCING BANK
DEBT
------------------------------------------------------ Appendix II:2.6
As of September 30, 1996, TVA had $3.2 billion of long-term debt held
by FFB. This debt was issued from 1985 to 1989, with maturities
ranging from 14 to 30 years and fixed interest rates ranging from 8.5
percent to 11.7 percent. FFB cannot call this debt and TVA cannot
prepay this debt unless it pays FFB the present value of the future
cash flows using current FFB interest rates.\12 This debt matures in
fiscal years 2003 through 2016. For fiscal years 1992 through 1996,
TVA had varying amounts of FFB debt outstanding.
FFB obtains its funds by borrowing from the Department of the
Treasury. FFB has a stated policy to provide funds at Treasury's
cost of money. Each loan made by FFB matches the terms and
conditions, except for the interest rate, of the corresponding loans
made by Treasury to FFB. FFB charges TVA the interest rate it incurs
on the Treasury borrowing, plus a fee of one-eighth-of-one-percent to
cover administrative costs.\13
Because the interest rate on TVA's FFB debt is based on the interest
rate paid by the Treasury on similar term debt plus a one-eighth of
one percent administrative fee, we concluded that Treasury is
recovering its cost of funds and that there is no net financing cost
to the federal government.
Recently, TVA asked FFB to allow it to repay this debt before its
maturity dates. However, TVA was not willing to incur the prepayment
premiums required under the terms of the existing loan contracts with
FFB. In 1995, the Congressional Budget Office (CBO) was asked to
review proposed legislation that would have authorized TVA to prepay
$3.2 billion in loans made by FFB without paying the prepayment
premiums. CBO estimated that enacting such legislation in 1996 would
have increased federal outlays by about $120 million per year through
2002, with declining amounts thereafter until the last notes matured
in the year 2016. We concur with CBO's assessment. This proposed
legislation was never introduced.
--------------------
\12 FFB charges the prepayment premium to protect itself from
incurring an economic loss on the prepayment. This premium is
calculated based on the difference between the book (face) value and
the Treasury market value of the loan. The loan's market value is
calculated based on the net present value of the future stream of
principal and interest payments the government gives up when FFB
accepts prepayment of a loan. We did not review the Congressional
Budget Office's calculation of the increase in federal outlays that
would result if TVA were allowed to repay its FFB debt without paying
the prepayment premiums.
\13 TVA also has the option of repurchasing the FFB bonds under
standard FFB prepayment provisions.
BPA'S TREASURY BONDS
------------------------------------------------------ Appendix II:2.7
As of September 30, 1996, BPA had $2.5 billion of medium- and
long-term debt held by Treasury in the form of BPA bonds. Interest
rates on this debt are fixed and are set using rates comparable to
the debt issued by U.S. government corporations with similar terms.
Some of this debt is callable by BPA. The call premium BPA paid was
also based on premiums for similar debt. The debt matures in fiscal
years 1997 through 2034. For fiscal years 1992 through 1996, BPA had
varying amounts of FFB debt outstanding.
We discussed the mechanics of the borrowing process with cognizant
BPA and Treasury representatives. In addition, we examined the
process by which Treasury sets interest rates and call premiums.
Because the BPA bonds result in a return to the Treasury that
approximates its cost of funds, we believe that there is no net cost
to the federal government.
ASSESSING THE RECOVERY OF
PENSION AND POSTRETIREMENT
BENEFITS
------------------------------------------------------ Appendix II:2.8
To assess whether pension and postretirement health benefits were
fully recovered by RUS, the PMAs, and TVA, we consulted with
representatives from the Office of Personnel Management's Office of
Actuaries. We determined that certain Civil Service Retirement
System (CSRS) pension benefits were not being recovered by RUS, the
PMAs, and TVA. We also determined that all postretirement health
benefits for current employees were not being recovered by RUS and
the PMAs. We determined that Federal Employee Retirement System
(FERS) pension benefits are currently being fully funded by employee
and employer contributions.
To calculate the cost of CSRS pension benefits that were not fully
recovered by RUS from borrowers or by the PMAs and TVA from rate
payers, and the cost of postretirement health benefits that were not
fully recoverd by RUS from borrowers or by the PMAs from ratepayers,
we reviewed SFFAS No. 5, Accounting for Liabilities of the Federal
Government, which requires all federal agencies to record the full
cost of pension and postretirement health benefits in financial
statements beginning in fiscal year 1997.
SFFAS No. 5 prescribes that the aggregate entry age normal (AEAN)\14
actuarial cost method be used to calculate pension expenses. We
consulted with actuaries from the Office of Personnel Management
(OPM) to obtain an understanding of how to apply the AEAN method to
estimate the amount by which employer and employee contributions
toward future CSRS pension benefits fall short of the normal cost of
those benefits.
We determined the applicable normal cost, under the AEAN method, of
CSRS pensions for fiscal year 1996. For CSRS employees, OPM reported
that in 1996, 25.14 percent of gross salaries was the full (normal)
cost to the federal government of benefits earned that year by
employees and that federal agencies contributed 7 percent and
employees contributed 7 percent to OPM for CSRS, leaving a funding
deficiency of 11.14 percent of each CSRS employee's annual salary.
This 11.14 percent funding deficiency is applicable to federal
agencies. To calculate the difference between the full (normal) cost
for CSRS pensions and the amount employees and the federal entities
contributed, we
-- estimated the number of full-time equivalent positions involved
in electricity-related activities at RUS, the PMAs and TVA,
based on information provided by each entity;
-- estimated the number of those employees covered by the CSRS
pension plan, based on (1) governmentwide information provided
by OPM on the percentage of employees covered by CSRS or (2)
information provided by the entity;
-- multiplied that number by the average salary\15 to estimate
total CSRS payroll expense; and
-- multiplied the resulting number by 11.14 percent, which,
according to OPM actuaries, represents the difference between
the normal cost of future CSRS pensions and combined employer
and employee contributions.
The result is an estimate of the additional amount the entities would
have had to contribute to fully fund CSRS pension benefits earned in
fiscal year 1996.
To estimate the cumulative net costs for fiscal years 1992 through
1996 under the AEAN method for future CSRS pensions, we multiplied
the net cost for 1996 by five. The resulting estimate of cumulative
net costs for CSRS pensions for the 5-year period, which we converted
to constant 1996 dollars, is conservative because the number of CSRS
employees has been declining. The annual net cost, or funding
shortfall, associated with CSRS pension benefits will be eliminated
over time as CSRS employees leave the government and are replaced
with FERS employees, provided that FERS pension benefits remain fully
funded.
In addition to pensions, federal employees are eligible to receive
postretirement health coverage, for which a portion of the premium is
paid by the federal government. While employed, neither federal
employees nor their employing agencies contribute funds to pay for
the federal government's portion of postretirement health benefits.
For applicable employees, the PMAs do not recover this cost from
ratepayers, and RUS does not recover this cost from borrowers. To
calculate the amount of the electricity-related costs for fiscal year
1996, we again used the AEAN method, which is prescribed by SFFAS No.
5 for estimating postretirement health benefit costs. We estimated
the number of relevant covered employees at each entity involved in
electricity-related activities. We multiplied this number for each
employee by the 82-percent governmentwide health benefits plan
participation rate, which we then multiplied by $2,183 (OPM's
estimate of the annual normal cost for postretirement health benefits
per participating employee for fiscal year 1996). The result of this
calculation approximates the normal cost of postretirement health
benefits for fiscal year 1996 and the amount the entities would have
had to contribute to fully fund postretirement health benefits earned
that year. As with CSRS pensions, to estimate the cumulative net
costs for fiscal years 1992 through 1996, we multiplied the net cost
for 1996 by five, and converted this amount to constant 1996 dollars.
It is important to note that our calculations of annual pension and
postretirement health benefits do not include any provision for
retirees of each entity because the relevant actuarial information
needed to do so was not available from OPM.
--------------------
\14 Under the AEAN method, which is based on dynamic economic
assumptions, including future salary increases, the actuarial present
value of projected benefits is allocated on a level basis over the
earnings or the service of the group between entry age and assumed
exit ages and should be applied to pensions on the basis of a level
percentage of earnings. The portion of this actuarial present value
allocated to a valuation year is called the "normal cost."
\15 We used governmentwide average salary information we obtained
from OPM for CSRS employees.
ASSESSING THE RECOVERY OF
OTHER COSTS
------------------------------------------------------ Appendix II:2.9
For this report, we defined other costs to include construction costs
for certain projects, environmental costs legislatively precluded
from recovery, power-related costs assigned to incomplete irrigation
projects, deferred payments, interest expense on store supplies,
legal costs incurred by the Department of Justice, and administrative
appropriations not recovered. As discussed below, to assess these
costs we used audited financial statements, cost reports, and/or
other provided information. Not all of the costs were applicable to
each agency.
We obtained information on recovery of construction costs relating to
the Teton Project (BPA), Russell Project (Southeastern), Truman
Project (Southwestern), and the Washoe and Mead-Phoenix Projects
(Western), by analyzing the PMA annual reports and other information
provided by the PMAs and operating agencies. For the Corps' Russell
Project, we also reviewed records of congressional hearings on the
project dating back to its initial approval in the 1960s.
We used cost reports and financial statements from the PMAs and
operating agencies to review environmental costs. We determined that
some environmental costs have been legislatively excluded from
recovery in rates. We also found some environmental costs not
legislatively excluded that are included in rates, but we could not
determine whether all such costs are included. Obtaining the data
necessary to make this determination was beyond the scope of the
assignment.
To identify the portion of power-related capital costs allocated to
incomplete and unfeasible irrigation facilities at Western's
Pick-Sloan program, we used (1) cost reports and estimates of the
power requirements for irrigation facilities prepared by the Bureau,
(2) cost allocation percentages prepared by the Bureau and Corps, and
(3) reconciliations prepared by Western in their Power Repayment
Studies and the Bureau's Statement of Project Construction Cost and
Repayment as of September 30, 1994. We determined that the capital
costs allocated to incomplete or unfeasible irrigation facilities
amounted to about $454 million as of September 30, 1994. Based on
our previous finding that these capital costs increased by about $5
million annually between fiscal years 1987 and 1994,\16
we estimated that the capital costs amounted to about $464 million as
of September 30, 1996. We did not verify the Bureau's cost-benefit
calculations for determining the feasibility of its irrigation
projects within the Pick-Sloan program.
To identify the portion of the Corps power-related operations and
maintenance (O&M) expenses that Western has allocated to incomplete
irrigation facilities for financial reporting and cost recovery
purposes, we reviewed the annual calculations made by Western to
allocate the Corps of Engineers' annual O&M expenses based on the
planned rather than the actual use of the irrigation facilities.
Western has had an outstanding balance of deferred interest and O&M
payments since at least 1988. Within the last 5 fiscal years, the
amount deferred ranged from a high of $250 million as of September
30, 1994, to a low of $81 million as of September 30, 1996. To
assess the impact on Treasury, we analyzed the net change in the
deferred payments amount in each of the last 5 years. Net increases
in the deferred amount in fiscal years 1992 through 1994 were
reflected as net costs to the federal government. Net decreases in
the deferred amount in fiscal years 1995 and 1996 were reflected as
net recoveries for the federal government.
Western has maintained an inventory of "stores supplies" (spare parts
used in performing maintenance, repairs, and upgrades of transmission
facilities), averaging almost $21 million over the 5 years from 1992
through 1996. However, Western has not paid interest on the
appropriated debt associated with this inventory. We estimated the
amount of interest that was not paid to Treasury each year by
multiplying the stores supplies balance as of September 30 of each of
the last 5 fiscal years by the average yield rate on 3-year
marketable Treasury bonds issued in each of those years. We used the
3-year bond rate because the stores inventory turns over about once
every 2 or 3 years.
We assessed the recovery of legal costs the Department of Justice
(DOJ) incurs on behalf of RUS. We determined that DOJ's legal costs
are not charged to RUS and are thus costs that the federal government
incurs on RUS' behalf. To identify DOJ's legal costs for RUS, we
obtained information from DOJ for fiscal years 1992 through 1996.
These costs include staff hours, salaries, benefits, travel, and
other costs. We also found that BPA and DOJ have an
intergovernmental agreement in place that provides for DOJ to bill
BPA for certain costs incurred. The agreement specifically covers
BPA's Washington Public Power Supply System and Tenaska litigation,
as well as DOJ's salary, travel, and certain other costs. We did not
assess whether this arrangement results in the full recovery of costs
DOJ incurs for BPA.
We determined from discussions with USDA officials that RUS does not
recover administrative appropriations through interest or other
charges to borrowers. To identify the electricity-related share of
RUS' administrative appropriation for fiscal years 1992 through 1996,
we obtained an estimate from USDA. According to USDA, these
administrative costs include funding for all direct and indirect
costs, except the pension and postretirement health benefits
previously discussed.
--------------------
\16 Federal Power: Recovery of Federal Investment in Hydropower
Facilities in the Pick-Sloan Program (GAO/T-RCED-96-142, May 2,
1996).
ASSESSING THE RISK TO THE
FEDERAL GOVERNMENT OF FUTURE
LOSSES FOR ELECTRICITY-RELATED
ACTIVITIES
-------------------------------------------------------- Appendix II:3
In assessing the risk of future losses beyond the net recurring costs
to the federal government from the electricity-related activities at
the PMAs, TVA, and RUS, we used the criteria for contingencies from
SFFAS No. 5, Accounting for Liabilities of the Federal Government.
According to SFFAS No. 5, "A contingency is an existing condition,
situation, or set of circumstances involving uncertainty as to
possible gain or loss to an entity. The uncertainty will ultimately
be resolved when one or more future events occur or fail to occur."
When a loss contingency exists, the likelihood that the future event
or events will confirm the loss or the incurrence of a liability can
range from probable to remote as follows:
-- Probable: The future confirming event or events are more likely
than not to occur.
-- Reasonably possible: The chance of the future confirming event
or events occurring is more than remote but less than probable.
-- Remote: The chance of the future event or events occurring is
slight.
We applied these criteria and considered different risk factors on
the basis of discussions with agency officials and industry experts,
analysis of financial and other data, and our professional judgment.
It is important to note that our assessment of the likelihood of loss
does not generally consider proceeds that the federal government
would receive from the sale of the assets of the RUS borrowers, the
PMAs, or TVA.
ASSESSING RISK OF LOSS TO
THE FEDERAL GOVERNMENT FOR
THE RURAL UTILITIES SERVICE
PORTFOLIO OF ELECTRIC LOANS
AND LOAN GUARANTEES
------------------------------------------------------ Appendix II:3.1
In order to assess the risk of future loss beyond the net recurring
costs to the federal government from the electricity-related
activities of RUS, we reviewed the $32.3 billion (as of September 30,
1996) RUS portfolio of electric loans and loan guarantees outstanding
to rural electric cooperatives. The portfolio consists of loans and
guarantees made to 782 distribution cooperatives and 55 Generation
and Transmission (G&T) cooperatives. We focused primarily on the
G&Ts, since their principal outstanding is approximately $22.5
billion, or about 70 percent of the RUS electric loan portfolio, and
they are generally higher risk loans. According to RUS officials,
the G&T borrowers generally have substantial capital investment and
debt and thus have higher-risk loans than those made to distribution
borrowers. The G&Ts are wholesale producers and are more vulnerable
to current competitive pressures. In addition, 19 of the 55 G&T
borrowers have invested in uneconomical nuclear projects.
We contacted Moody's Investors Service to obtain their views on the
risk of loss from the RUS portfolio and to gain an understanding of
issues facing the cooperatives. We reviewed the list of 13 G&T
borrowers that RUS has identified as financially stressed. According
to RUS reports, about $10.5 billion of the $22.5 billion in G&T debt
is owed by the 13 financially stressed borrowers. We ascertained
from RUS why each of the 13 was placed on the list. Of these, four
G&T borrowers are in bankruptcy with about $7 billion in outstanding
debt. The remaining 9 borrowers have investments in uneconomical
nuclear generating plants and/or have requested or plan to request
financial assistance from RUS. We obtained and reviewed agency
documents with write-off information for fiscal years 1992 through
1996. We also discussed with RUS and DOJ officials the loan
write-offs to date, the 13 financially stressed borrowers, and the
potential for future write-offs.
To assess the ability of RUS G&T cooperatives to withstand
competitive pressures, we analyzed the average revenue per
kilowatthour (kWh) of 33 G&T borrowers that are not currently
considered financially stressed by RUS. We excluded the 9 G&Ts that
only transmit electricity and the 13 financially stressed borrowers.
As of September 30, 1996, the loans outstanding for these 33 G&Ts
were about $11.7 billion of the $22.5 billion in G&T loans
outstanding. We compared the average revenue per kWh for these
borrowers with North American Electric Reliability Council (NERC)
regional averages for investor-owned utilities (IOUs) and
publicly-owned generating utilities (POGs). We obtained the average
revenue per kWh for the 33 borrowers from RUS statistical reports and
verified the numbers to the borrowers' annual reports and the
borrowers' audited financial statements, when available. In
addition, RUS staff verified the numbers. We obtained a report on
electric cooperatives from Moody's Investors Service, which
corroborated our data. (See appendix III for a further discussion of
average revenue per kWh.)
ASSESSING RISK OF FUTURE
LOSS TO THE FEDERAL
GOVERNMENT FOR THE PMAS AND
TVA
------------------------------------------------------ Appendix II:3.2
To assess the risk of future loss beyond the net recurring costs to
the federal government from the electricity-related activities of the
PMAs and TVA, we analyzed each agency based on several key factors.
We interviewed government bond analysts at Fitch Investors Service
and at Moody's to determine the factors they use to analyze the
financial condition of electric utilities and provide bond ratings.
The specific factors that we used to analyze each agency included
cost of electricity production and rates, key financial ratios,
generating mix, competitive environment, management actions, and
legislative and other factors. Because of the unique characteristics
of each PMA and TVA, not all factors were applicable to each agency.
We also identified mitigating factors that reduce the probability of
loss for each agency. Based on our assessment of the risks and
mitigating factors, we determined whether the risk of future loss
beyond the net recurring costs to the federal government was
probable, reasonably possible, or remote. For BPA, we assessed the
risk of loss (1) through the year 2001 and (2) after the year 2001.
For TVA, we assessed the risk of loss (1) with protections from
competition and (2) without barriers to competition.
To assess the competitiveness of the PMAs and TVA, we compared the
average revenue per kWh for wholesale sales of each entity to the
average revenue per kWh for wholesale sales of IOUs and POGs in the
primary NERC region that each entity operates. We also compared the
average revenue per kWh of each of the three PMAs' rate-setting
systems to IOUs and POGs in each system's NERC region.\17 We
determined that IOUs and POGs were the appropriate "industry group"
to compare to the PMAs and TVA because they generate and transmit
electricity and sell some power at wholesale. Our comparisons are
particularly relevant because many power customers are primarily
concerned with cost of production and resultant electricity rates
when choosing their electricity suppliers. We did not include
nongenerating publicly owned utilities. These utilities ordinarily
have no generating assets and thus are not comparable from an
operating or financial perspective.
To assess the flexibility of BPA and TVA to respond to competitive
pressures, we computed the ratio of financing costs to revenue for
each entity and nonfederal utilities by dividing financing costs by
operating revenue. The financing costs include interest expense on
short-term and long-term debt, appropriated debt for BPA and TVA, and
preferred and common stock dividends for the IOUs. Preferred and
common stock dividends were included in the IOUs' financing costs to
reflect the difference in the capital structure of these entities
from BPA and TVA. We also computed the ratio of fixed financing
costs to revenue for TVA and neighboring IOUs. For TVA, we limited
our comparison group to 11 IOUs\18 that border on TVA's service area
because industry experts told us that due to the cost of transmitting
electricity, TVA's competition would most likely come from IOUs
located close to its service area. For example, the Bristol Virginia
Utilities Board has terminated its power contract with TVA and agreed
to purchase its electric power from Cinergy, one of the IOUs in our
comparison group. We calculated this ratio by dividing financing
costs less common stock dividends by operating revenue for the fiscal
year. We excluded common stock dividends from the IOUs' financing
costs because they are not contractual obligations that have to be
paid.
To assess changes in the environment in which BPA operates and
potential measures that may be taken in response to these changes, we
reviewed the final report from the Comprehensive Review of the
Northwest Energy System that was initiated by the governors of the
states that BPA serves. Since the review's recommendations have not
been implemented, we did not assess the effect they would have on the
federal government's financial risk. In addition, we examined the
extent to which BPA's financial reserves provide additional
flexibility in BPA's attempts to respond to competitive pressures.
We did not, however, perform an independent evaluation of BPA's $325
million fish contingency reserve or the credits BPA takes annually
for fish migration costs.
To compare the amount of deferred assets and capital costs that TVA
has compared to neighboring IOUs, we computed the following two
ratios for 1996.
-- The ratio of accumulated depreciation and amortization to gross
property, plant and equipment (PP&E) was calculated by dividing
accumulated depreciation and amortization by gross PP&E at
fiscal year-end.
-- The ratio of deferred assets to gross PP&E was calculated by
dividing deferred assets by gross PP&E at fiscal year-end.
Deferred assets include construction work-in-progress and
deferred nuclear units (for TVA only). Deferred nuclear units
are included for TVA because they are treated by TVA as
construction work-in-progress (that is, not depreciated).
To compute the investment in utility plant per megawatt of generating
capacity for the PMAs, TVA, and nonfederal utilities, we divided
gross PP&E by the utilities' generating capacity at fiscal year-end.
For the IOUs, we used the nameplate generating capacity at fiscal
year-end 1995. For TVA, we used the winter net dependable generating
capacity as of September 30, 1996. We used TVA's capacity figure as
of September 30, 1996, to reflect the two nuclear units that TVA
brought on line during fiscal year 1996. For the IOUs, we computed
average system retail rates by dividing total retail electricity
revenues by total kilowatt hours sold. To calculate the average
system retail rates\19 for TVA, we multiplied the percentage of
retail sales by TVA's residential, commercial, and industrial sales
by the retail sales for each category. Then, we totaled these
amounts to compute the weighted average system retail rate for TVA.
To assess the status of TVA's power program, we examined the history
and current operation of TVA's nuclear power program and TVA's
prospects for converting the partially completed Bellefonte Nuclear
Plant to a fossil plant. We focused on TVA's nuclear power program
because it is associated with a substantial portion of TVA's $27.9
billion of debt, and because it has experienced problems over the
past 20 years. We reviewed previous GAO, TVA, and Nuclear Regulatory
Commission reports on TVA's nuclear power program. We examined TVA's
program for operating, maintaining, and upgrading its nonnuclear
power assets, primarily its coal-fired and hydroelectric units. The
coal-fired and hydroelectric units are important because in fiscal
year 1996, approximately 65 percent of TVA's generation was from
coal-fired units and 11 percent was from hydroelectric units. For
the coal-fired and hydroelectric units, we reviewed TVA's projected
capital expenditures through the year 2001. We obtained data on
TVA's plans to upgrade or retire these units and its assessments of
the costs of complying with environmental requirements, including the
Clean Air Act requirements.
To gain an understanding of the concerns of the PMAs' customers, we
contacted organizations representing major PMA customers. These
groups were formed to facilitate communication between the PMAs and
their customers and to raise concerns where appropriate. For all
four PMAs, we obtained the groups' perspectives on the impact of
deregulation on the electricity industry. For BPA, we also obtained
the groups' viewpoints on the reasonableness of BPA's attempts to
renew contracts with existing customers before they expire in 2001.
Because most of our concerns with Southeastern, Southwestern, and
Western relate to individual rate-setting systems, we specifically
addressed issues related to these systems' competitiveness with the
appropriate customer group. Where the customer group corroborated
information from the three PMAs on the competitiveness of an
individual rate-setting system, we did not independently verify it,
and we attributed any views reported.
To gain an understanding of the concerns of TVA's customers, we
contacted regional associations that represent TVA's distributors and
large industrial customers. We also interviewed officials from some
of TVA's largest distributors (which represent over 30 percent of
TVA's energy sales), including the municipal utilities of
Chattanooga, Knoxville, Memphis, and Nashville, Tennessee. We
interviewed officials from the Bristol, Tennessee, and Fort Payne,
Alabama, utilities in order to gain the perspectives of TVA's smaller
municipal distributors. We also interviewed officials from the
Bristol Virginia Utilities Board because the utility has terminated
its power contract with TVA and agreed to purchase its electric power
from another utility beginning January 1, 1998. We interviewed
officials from the Four County Electric Power Association in
Columbus, Mississippi, because the utility had terminated its power
contract with TVA, but the utility subsequently withdrew its
termination notice and decided to remain in the TVA system. We
analyzed the provisions of TVA's power contracts to determine how
difficult it would be for a distributor to cancel its contract. We
examined recent modifications that some distributors have made to the
cancellation notice requirements in their contracts. We also
examined recent agreements not to exercise termination rights that
some distributors have signed.
A list of the organizations that we contacted during the course of
our work follows. We conducted our review between January 1997 and
July 1997 in accordance with generally accepted government auditing
standards. We obtained written comments on a draft of our report,
which are contained in appendixes X through XIII.
--------------------
\17 Unlike the three PMAs, BPA is comprised of a single rate-setting
system.
\18 The 11 IOUs and their subsidiary utilities used in our comparison
included (1) American Electric Power Company (including Appalachian
Power, Columbus Southern Power, Indiana Michigan Power, Kentucky
Power, Kingsport Power, Ohio Power, and Wheeling Power), (2) Carolina
Power & Light Company, (3) Cinergy Corp. (including Cincinnati Gas &
Electric and PSI Energy), (4) Dominion Resources, Inc. (including
Virginia Electric Power), (5) Duke Power Company, (6) Entergy
Corporation (including Arkansas Power & Light, Gulf States Utilities,
and Mississippi Power & Light), (7) Illinova Corporation (including
Illinois Power), (8) KU Energy Corp. (including Kentucky Utilities
Co.), (9) LG&E Energy Systems (including Louisville Gas and
Electric), (10) SCANA Corporation (including South Carolina Electric
& Gas), and (11) The Southern Company (including Alabama Power,
Georgia Power, Gulf Power, and Mississippi Power).
\19 TVA sells wholesale power to its distributors who then sell it at
retail rates. In performing this calculation, we used TVA's
distributors' retail rates.
ORGANIZATIONS THAT GAO
CONTACTED
-------------------------------------------------------- Appendix II:4
The following are the organizations that GAO contacted during the
course of its work.
FEDERAL AGENCIES
------------------------------------------------------ Appendix II:4.1
Congressional Budget Office
Department of Agriculture, Office of the Inspector General and Rural
Utilities Service
Department of Defense, U.S. Army Corps of Engineers
Department of Energy, including the Energy Information Administration
and Office of the Inspector General
Department of the Interior, Bureau of Reclamation
Department of Justice
Department of Treasury, including the Federal Financing Bank
Nuclear Regulatory Commission, Atlanta Region
Office of Management and Budget
Office of Personnel Management, Office of Actuaries
BOND RATING AGENCIES
------------------------------------------------------ Appendix II:4.2
Fitch Investors Service, Inc., New York, New York
Moody's Investors Service, New York, New York
INDEPENDENT PUBLIC
ACCOUNTING FIRMS
------------------------------------------------------ Appendix II:4.3
Coopers & Lybrand L.L.P.
KPMG Peat Marwick LLP
Price Waterhouse LLP
Urbach Kahn and Werlin P.C.
ELECTRIC UTILITIES OR
HOLDING COMPANIES
------------------------------------------------------ Appendix II:4.4
Entergy, New Orleans, Louisiana
Southern Company, Atlanta, Georgia
CUSTOMER REPRESENTATIVE OR
TRADE GROUPS
------------------------------------------------------ Appendix II:4.5
Direct Service Industries, Inc., Portland, Oregon
Electric Power Supply Association, Washington, D.C.
Northern California Power Agency, Palo Alto, California
Northwest Irrigation Utilities, Portland, Oregon
Northwest Requirements Utilities, Portland, Oregon
Pacific Northwest Utilities Conference Committee, Portland, Oregon
Public Power Council, Portland, Oregon
Southeastern Federal Power Customers, Alabama
Southwestern Power Resources Association, Tulsa, Oklahoma
Tennessee Valley Energy Reform Coalition, Knoxville, Tennessee
Tennessee Valley Industrial Committee/Associated Valley Industries,
Columbia, Tennessee
Tennessee Valley Public Power Association, Chattanooga, Tennessee
TVA DISTRIBUTORS
------------------------------------------------------ Appendix II:4.6
Bristol, Virginia
Bristol, Tennessee
Chattanooga, Tennessee
Four County Electric Power Association, Columbus, Mississippi
Fort Payne, Alabama
Knoxville, Tennessee
Memphis, Tennessee
Nashville, Tennessee
Paducah, Kentucky
AVERAGE REVENUE PER KILOWATTHOUR
FOR WHOLESALE SALES
========================================================= Appendix III
AVERAGE REVENUE PER
KILOWATTHOUR IS AN INDICATOR OF
POWER PRODUCTION COSTS
------------------------------------------------------- Appendix III:1
In a competitive market for a relatively homogeneous product like
electricity, being among the lowest cost producers is generally the
most important factor in determining competitive position. As the
electricity industry responds to deregulation, the ability to keep
power production costs low will enhance an entity's competitive
position. To assess power production costs, we examined the average
revenue per kilowatthour (kWh) for each entity in our report.
The average revenue per kWh for wholesale sales (sales for resale) is
referred to as average revenue per kWh. The average is calculated by
dividing total revenue from the sale of wholesale electricity by the
total number of wholesale kilowatthours sold. Because the power
marketing administrations (PMAs), publicly-owned generating utilities
(POGs), and rural electric cooperatives generally recover costs
through rates with no profit, average revenue per kWh should reflect
the power production costs of the PMAs, POGs, and rural electric
cooperatives. This assumes that the entity's competitive position is
such that it can charge sufficiently high rates to recover all costs
from customers. For investor-owned utilities (IOUs), average revenue
per kWh should reflect cost plus the regulated rate of return. Given
that a large portion--an average of 79 percent over the last 5
years--of IOU rate of return (net income) is paid out in common stock
dividends, which is a financing cost, average revenue per kWh also
approximates power production costs for IOUs.
The Energy Information Administration (EIA) cautions that average
revenue per unit of energy sold should not be used as a substitute
for the price of power. The price that any one utility charges for
wholesale energy comprises numerous transaction-specific factors,
including the fees charged for reserving a portion of capacity,
consumption during peak and off-peak periods, and the use of the
facilities. These fees are influenced by factors such as time of
delivery, quantity of energy, surcharges, and reliability of supply.
For example, some Western project revenues include a legislatively
mandated surcharge that is not related to production costs.
In the current electricity market, utilities generally are able to
recover their fixed costs from captive retail customers. When
competing for new wholesale customers, utilities with excess capacity
that are able to recover their fixed costs from retail customers are
able to sell excess output at a price that does not reflect the full
cost of producing that electricity (i.e., they can sell that power at
marginal cost). Consequently, in some cases average revenue per kWh
may not reflect full power production costs. However, despite these
limitations, average revenue per kWh is a good indicator of
production costs since over time utilities must recover all costs to
remain in business. We therefore believe that average revenue per
kWh reflects today's competitive environment. In addition, bond
rating services such as Moody's Investors Service use average revenue
per kWh as one factor to assess competitive position.
In volume 1 and appendixes VI, VII, and VIII, we compare the average
revenue per kWh for RUS Generation and Transmission Cooperatives
(G&T) borrowers, the three PMAs, and BPA to the North American
Electric Reliability Council (NERC)\1 regions in which they operate
because the factors related to individual entities' regional markets
are still the key determinant of the competitive position of each
entity. NERC consists of 10 regional reliability councils\2 and
encompasses essentially all the power systems of the contiguous
United States, as well as parts of Canada and Mexico. Because the
latest available data on average revenue per kWh by NERC region are
for 1995, we used the 1995 NERC configuration, which shows only nine
councils. A new regional council that encompasses much of Florida
was added in 1996. Figure III.1 illustrates the location of the NERC
regions of the contiguous United States as of 1995.
Figure III.1: NERC Regions of
the Contiguous United States,
as of 1995
(See figure in printed
edition.)
Source: North American Electric Reliability Council.
--------------------
\1 NERC was formed by the electric utility industry to promote the
reliability and adequacy of the bulk power supply in the electric
utility systems of North America.
\2 In addition to its 10 regional councils, NERC has 1 affiliate
council member, the Alaska Systems Coordinating Council (ASCC).
SUMMARY OF NET COSTS
========================================================== Appendix IV
The net costs to the federal government resulting from its
involvement in the electricity-related activities of four of the
Department of Energy's power marketing administrations (PMAs),\1
Tennessee Valley Authority (TVA), and the Department of Agriculture's
Rural Utilities Service (RUS) are summarized in table IV.1. The
first four categories of net costs (net financing, loan write-offs,
pensions and postretirement health benefits, and construction) are
discussed in volume 1 of this report. The remaining categories are
referred to as "Other" net costs in volume 1 and are briefly
explained below. See appendix II for a discussion of our methodology
for estimating the net costs. Also see our September 19, 1996,
report for additional information regarding some of these costs.\2
Table IV.1
Net Costs for Fiscal Year 1996 and
Fiscal Years 1992 Through 1996 in
Constant 1996 Dollars for RUS, TVA, and
the PMAs
(Dollars in millions)
Total Costs
----------------------
1992-1996
(Constant
1996
RUS TVA BPA SEPA SWPA WAPA 1996 dollars)
-------- ------ ------ ------ ------ ------ ------ -------- ------------
Net $874 $377 $68 $42 $98 $1,459 $6,941
financi
ng\
Loan 982 982 1,049
write-
offs
Benefits 1 $1 21 3 2 11 39 199
Construc 30\ 30 139\
tion
Environm 28 28 144
ental
Deferred (114) (114) (74)
payments
Administ 21 21 110
rative
appropr
iations
DOJ 1
costs
Irrigati 16 16 80
on
Stores 1 1 6
invento
ry
================================================================================
Total $1,878 $1 $398 $101 $44 $40 $2,462 $8,597
--------------------------------------------------------------------------------
Note: Totals may not add due to rounding.
--------------------
\1 The PMAs are Bonneville, Southeastern, Southwestern, and Western
Area Power Administrations, which are referred to as BPA, SEPA, SWPA,
and WAPA, respectively.
\2 Power Marketing Administrations: Cost Recovery, Financing, and
Comparison to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
1996).
NET FINANCING COSTS
-------------------------------------------------------- Appendix IV:1
For RUS, the net financing cost represents the difference between the
annual interest income received by the federal government from RUS
borrowers and the federal government's annual interest expense to
provide the funds. For the PMAs, the net financing cost represents
the difference between interest income received by the federal
government on appropriated debt and the federal government's related
interest expense. See appendix II for a further description of the
methodologies used in estimating net financing costs and appendix V
for more information about RUS' net financing costs.
LOAN WRITE-OFFS
-------------------------------------------------------- Appendix IV:2
RUS has recently written off a substantial dollar amount of loans to
rural electric cooperatives under Department of Justice (DOJ)
authority. RUS wrote off about $982 million of debt in fiscal year
1996 and a total of about $1.05 billion (in constant 1996 dollars)
over the 5-year period 1992-1996. In addition, at the time of our
review, RUS had written off $502 million in fiscal year 1997. The
most significant write-offs are related to Generation and
Transmission Cooperatives (G&T) borrowers. See volume 1 of this
report for more information.
PENSION AND POSTRETIREMENT
HEALTH BENEFITS
-------------------------------------------------------- Appendix IV:3
RUS, the PMAs, and TVA\3 do not recover the full costs to the federal
government of providing Civil Service Retirement System (CSRS)
pension benefits to current federal employees. Nor do RUS and the
PMAs recover the full costs to the federal government of providing
postretirement health benefits to current federal employees. We
estimate that the net CSRS pension and postretirement health benefit
cost totaled about $39 million in fiscal year 1996 and about $199
million in constant 1996 dollars over the 5-year period 1992-1996.\4
--------------------
\3 TVA has a small number of employees who transferred to TVA from
federal agencies and continued to be covered by federal pension
programs--CSRS or the Federal Employees Retirement System (FERS).
TVA has its own pension system, which is fully funded. TVA employees
are not covered by the Federal Employees Health Benefits Program
(FEHBP).
\4 Our analysis covered pension and postretirement health benefit
costs for current employees only. The costs associated with retired
employees were not considered because the data necessary to do so was
not available from the Office of Personnel Management (OPM).
CONSTRUCTION COSTS
-------------------------------------------------------- Appendix IV:4
Construction costs are comprised of interest that is not paid to
Treasury each year for two construction projects. As discussed in
appendix VII, interest is capitalized each year on the nonoperational
portion of the Russell Project, marketed by Southeastern. The
unrecovered interest totaled about $30 million in fiscal year 1996
and about $138 million (in constant 1996 dollars) over the 5-year
period 1992-1996. In addition, interest was not paid to Treasury on
the money spent to construct the Teton Dam, which would have been
marketed by BPA. The Teton Dam failed in 1976 when construction was
nearly complete. The Teton costs have been carried on the Bureau of
Reclamation's books as construction work-in-progress even though
construction was halted 20 years ago, and no interest has accrued
since 1976. The unrecovered interest related to the Teton Dam
totaled about $236,000 in fiscal year 1996 and about $1.2 million (in
constant 1996 dollars) over the 5-year period 1992-1996.
ENVIRONMENTAL MITIGATION COSTS
-------------------------------------------------------- Appendix IV:5
Two projects, the Central Valley Project's Shasta Dam and the
Colorado River Storage Project's Glen Canyon Dam, have incurred
power-related environmental mitigation costs that have been
legislatively excluded from Western's power rates. The 1991 Energy
and Water Development Appropriations Act specified that any increases
in purchased power at the Shasta Dam caused by bypass releases
related to fisheries preservation in the Sacramento River not be
allocated to power. Western officials believe that the bypass
releases will be eliminated or minimized by the construction of a
temperature control device at the Shasta Dam, which was recently
completed. These net costs totaled about $15.3 million in fiscal
year 1996 and about $53.8 million (in constant 1996 dollars) over the
5-year period 1992-1996.
The Grand Canyon Protection Act of 1992 exempted from recovery
certain costs of mitigating the environmental impact of river flow
fluctuations at the Glen Canyon Dam. The act states that certain
costs of environmental impact studies related to the Glen Canyon Dam
are not to be repaid by power customers, but it includes a provision
that these costs could become the responsibility of the power
customers under certain circumstances. The power-related costs for
environmental mitigation at the Glen Canyon Dam totaled about $12.8
million in fiscal year 1996 and about $90.3 million (in constant 1996
dollars) over the 3-year period since the legislative exemption,
1994-1996.
DEFERRED PAYMENTS
-------------------------------------------------------- Appendix IV:6
As of September 30, 1996, Western had deferred operations and
maintenance (O&M) and interest expense payments totalling about $81
million. This balance was $114 million less than the $195 million
outstanding as of September 30, 1995. Because of the net repayments
in fiscal years 1995 ($56.2 million in constant 1996 dollars) and
1996 ($114 million) of interest and O&M expenses deferred in prior
years, the deferred payment figures in table IV.1 are negative.
Deferred payments are to be repaid to Treasury, with interest.
Western officials expect to recover the majority of the deferred
payments outstanding as of September 30, 1996, over time.
ADMINISTRATIVE APPROPRIATIONS
-------------------------------------------------------- Appendix IV:7
The annual administrative appropriation to RUS includes salary
expenses for RUS employees as well as travel, data processing, and
other administrative support expenses. These costs are not passed on
to RUS borrowers. The estimated electricity-related share of the RUS
administrative appropriation was about $21 million in fiscal year
1996 and about $110 million (in constant 1996 dollars) over the
5-year period 1992-1996.
DEPARTMENT OF JUSTICE COSTS
-------------------------------------------------------- Appendix IV:8
The DOJ costs primarily represent hours worked by DOJ attorneys on
litigation related to RUS' electricity-related activities. In 1996,
DOJ attorneys spent about 5,700 hours working on RUS cases. These
costs are not charged to RUS and therefore are not passed on to RUS
borrowers. Judiciary costs related to RUS include salaries and
benefits received by DOJ attorneys and expenses for travel, printing,
and expert witnesses. We estimate that DOJ's total judiciary costs
on behalf of RUS were about $453,000 in fiscal year 1996 and about
$1.4 million (in constant 1996 dollars) over the 5-year period
1992-1996.
IRRIGATION
-------------------------------------------------------- Appendix IV:9
Substantial capital costs for hydropower facilities and water storage
reservoirs of the Pick-Sloan Missouri Basin Program have been
allocated to authorized irrigation facilities that are incomplete and
infeasible. Western is currently selling electricity to power
customers that irrigators would have used if the irrigation projects
had been completed. If the costs had been allocated based on actual
use, they would have been allocated primarily to power and recovered
through power rates within 50 years, with interest. We estimate that
these capital costs--which we previously reported increased by an
average of nearly $5 million annually between fiscal years 1987 and
1994,\5 --totaled about $464 million as of September 30, 1996.
Interest on the $464 million in capital expenditures is not being
paid. Using the 3 percent interest rate that was in effect for power
projects when construction began, we estimate that the net interest
cost was about $13.8 million in fiscal year 1996 and about $70.6
million (in constant 1996 dollars) over the 5-year period 1992-1996.
In addition, annual O&M expenses that otherwise would have been
allocated primarily to power and repaid from electricity rates have
also been allocated to the incomplete irrigation facilities. If
these expenses had been allocated to power, they would have been
included in Western's annual O&M expenses and recovered from power
customers. We estimate that the net irrigation O&M expense was about
$2.1 million in fiscal year 1996 and about $9.8 million (in constant
1996 dollars) over the 5-year period 1992-1996.
--------------------
\5 Federal Power: Recovery of Federal Investment in Hydropower
Facilities in the Pick-Sloan Program (GAO/T-RCED-96-142, May 2,
1996).
STORES INVENTORY
------------------------------------------------------- Appendix IV:10
Western has maintained an inventory of "stores supplies," which are
spare parts used in performing maintenance, repairs, and upgrades of
transmission facilities, averaging almost $21 million over the 5-year
period 1992-1996. As noted by Western's external financial auditor,
Western has not paid interest to Treasury on the amount of money
spent to purchase this inventory. However, in response to our
questions, Western officials stated that they will begin recovering
interest on the stores supplies in fiscal year 1997. We estimate
that the net interest expense associated with the stores supplies was
about $1.2 million in fiscal year 1996 and about $6.1 million (in
constant 1996 dollars) over the 5-year period 1992-1996.
RURAL UTILITIES SERVICE'S NET
FINANCING COST
=========================================================== Appendix V
A net financing cost exists in the Rural Utilities Service (RUS)
electric program because the annual interest income received from RUS
borrowers is substantially less than the federal government's annual
interest expense to provide the funds to the electric borrowers.
Interest income is affected by favorable rates and terms given to
some borrowers and also by financially troubled RUS borrowers who
have missed scheduled loan payments. According to RUS reports, about
$10.5 billion is owed by 13 financially stressed wholesale producers
that we refer to as Generation and Transmission Cooperatives (G&T)
borrowers. See appendix VI for a risk assessment of the RUS loan
portfolio.
As shown in table V.1, using the portfolio methodology discussed in
appendix II, we estimate that net financing costs (interest expense
minus interest income) to the federal government for the RUS electric
program for fiscal year 1996 were about $874 million; cumulatively,
over the last 5 years, we estimate that the net financing costs
totaled about $3.8 billion (in constant 1996 dollars). These net
financing costs reflect net interest expense incurred by Treasury in
providing the funding for RUS electric loans; therefore, they do not
correspond to RUS appropriations for these years.
Table V.1
Financing Costs to the Government
(Dollars in millions)
1992-1996
(Constant
1996
1996 dollars)
------------------------------------------------ ------ ------------
Interest income
Electric loans $1,853 $10,813
Interest expense
Debt to U.S. government 2,477 13,396
(FFB/Treasury)
Debt to private lenders 250 1,229
======================================================================
Net financing costs $(874) $(3,812)
----------------------------------------------------------------------
INTEREST INCOME
--------------------------------------------------------- Appendix V:1
RUS interest income is initially affected by favorable loan rates
given to some borrowers compared to the government's cost of
borrowing. Until the Rural Electrification Act was amended in 1973,
almost all financing was through direct loans from the Rural
Electrification Administration (REA) to electric borrowers at a fixed
rate of 2 percent with maturities up to 35 years. However, the 1973
amendment to the act increased the interest rate on the direct loans
from 2 percent to 5 percent. At the same time, loans were also made
available (through REA) to borrowers from the newly created Federal
Financing Bank (FFB) at the cost of money to the government. In
1993, the act was amended again, and the direct loan standard rate of
5 percent was changed to provide direct loans with an interest rate
that is (1) tied to an index of municipal borrowing rates or (2)
fixed at 5 percent. Most loans are now made at the municipal rate
with or without a 7-percent cap. Certain borrowers with customers
that have low consumer and household incomes and high residential
retail rates qualify for a loan at the 5-percent hardship interest
rate. See appendix I for a description of RUS' electric loans.
In addition to the favorable interest rates received by some
borrowers, RUS interest income is also affected by financially
stressed borrowers' failure to make scheduled loan payments.
According to RUS reports, about $10.5 billion of the $22.5 billion in
G&T debt is owed by 13 financially stressed G&T borrowers. RUS
defines financially stressed borrowers as those borrowers that have
defaulted on their loans, had their loans restructured but continue
to experience financial difficulties, declared bankruptcy, or
formally requested financial assistance from RUS. Interest income is
not recorded on delinquent debt until it is received.
Financially stressed borrowers' failure to make scheduled payments
can have a significant impact on interest income. For example, one
G&T borrower, Cajun Electric, has not been required to make interest
payments on its $4.2 billion debt since filing for bankruptcy in
December 1994. In addition, Cajun made total principal payments of
only about $19 million from December 1994 through the end of fiscal
year 1996. Based on Cajun's contractual interest rate of about 8.6
percent, RUS has forgone interest income of about $30 million per
month, or about $1 million per day, since December 1994. In the
meantime, the government continues to incur interest expense on
financing related to this loan.
INTEREST EXPENSE
--------------------------------------------------------- Appendix V:2
The federal government's annual interest expense on funds provided
for the RUS electric program is determined based on outstanding RUS
borrowing from FFB, Treasury, and private lenders. Debt to FFB and
Treasury totaled $27.5 billion (see table V.2) while debt to private
lenders totaled about $2.7 billion for the fiscal year ending
September 30, 1996.
Table V.2
Weighted Average Interest Expense for
Fiscal Years 1992 Through 1996
(Dollars in millions)
1992 1993 1994 1995 1996
-------------------- ---------- ---------- ---------- ---------- ----------
Debt to FFB/ $27,881.9 $27,567.8 $27,387.0 $27,855.3 $27,484.6
Treasury
Weighted average .09505 .09323 .09229 .09134 .09012
Treasury rate
================================================================================
Weighted average $2,650.2 $2,570.1 $2,527.5 $2,544.3 $2,476.9
interest expense
--------------------------------------------------------------------------------
FFB debt on the electric program totaled $20.5 billion as of
September 30, 1996. FFB obtains funds to make loans from Treasury.
The RUS electric program also had a total of $7 billion in direct
borrowing from Treasury at the end of fiscal year 1996. As shown in
table V.2, to calculate the federal government's interest expense for
RUS lending activities, we multiplied the total RUS debt owed to
Treasury and FFB by the annual weighted average Treasury rate for
each fiscal year.
To calculate interest expense for RUS debt with private lenders, we
totaled the actual amounts paid to the lenders based on RUS audited
financial statements and supporting documents. In conjunction with
certain troubled debt restructuring, RUS assumed notes payable to
private lenders for debt it previously guaranteed. A substantial
portion of these balances is owed to the National Rural Utilities
Cooperative Finance Corporation, a private lender to rural electric
borrowers. The notes bear interest at rates ranging from 7.13 to
10.70 percent and mature through the year 2020.
RISK ASSESSMENT FOR THE RURAL
UTILITIES SERVICE ELECTRIC
PORTFOLIO
========================================================== Appendix VI
From fiscal year 1996 through July 31, 1997, the Rural Utilities
Service (RUS) wrote off $1.5 billion in electric loans.\1 As of
September 30, 1996, $10.5 billion of the $32.3 billion total electric
portfolio represented loans to borrowers that are in bankruptcy or
otherwise financially stressed. It is probable that the federal
government will continue to incur substantial losses from loan
write-offs relating to RUS borrowers that are currently bankrupt or
financially stressed. It is also probable that future losses will
arise from other RUS borrowers with high production costs and the
inability to raise rates because of regulatory and/or market
pressures.
--------------------
\1 These write-offs were included in our analysis of net costs to the
federal government in volume I.
THE FEDERAL GOVERNMENT'S
FINANCIAL INVOLVEMENT
-------------------------------------------------------- Appendix VI:1
As of September 30, 1996, the RUS electric loan and loan guarantee
portfolio totaled $32.3 billion. The bulk of the portfolio is made
up of loans to the Generation and Transmission Cooperatives (G&Ts).
The principal outstanding on these G&T loans is approximately $22.5
billion, about 70 percent of the RUS electric loan portfolio.
Distribution borrowers make up the remaining 30 percent of the
electric portfolio. Most of the RUS electric loans and loan
guarantees were made during the late 1970s and early 1980s. For
example, from fiscal years 1979 through 1983, RUS approved loans and
loan guarantees of about $29 billion, whereas during fiscal years
1992 through 1996, it approved a total of about $4 billion in
electric loans and loan guarantees. There are currently 55 G&T
borrowers and 782 distribution borrowers. Our review focused on the
G&T loans since they make up the majority, in terms of dollars, of
the portfolio and generally pose the greatest risk of loss to the
federal government. The federal government incurs financial losses
when borrowers are unable to repay the balance owed on their loans
and the government does not have sufficient legal recourse against
the borrower to recover the full loan amount. In all instances, G&T
loans are collateralized; however, RUS has never foreclosed on a
loan. RUS generally has been unable to successfully pursue
foreclosure once the borrower files for bankruptcy because the
borrower's assets are protected until the proceedings are settled.
In addition, in recent cases where debt was written off, the
government forgave the debt and therefore will not attempt to pursue
further collection.
SUBSTANTIAL LOAN WRITE-OFFS
OCCURRED IN RECENT YEARS
-------------------------------------------------------- Appendix VI:2
Under Department of Justice (DOJ) authority, RUS has recently written
off a substantial dollar amount of loans to rural electric
cooperatives. The total amount of debt written off between fiscal
year 1992 and July 31, 1997, is about $1.5 billion. The most
significant write-offs relate to two G&T loans. In fiscal year 1996,
one G&T made a lump sum payment of $237 million to RUS in exchange
for RUS writing off and forgiving the remaining $982 million of its
RUS loan balance. The G&T's financial problems began with its
involvement as a minority-share owner in a nuclear project that
experienced lengthy delays in construction as well as severe cost
escalation. When construction of the plant began in 1976, its total
cost was projected to be $430 million. However, according to the
Congressional Research Service, the actual cost at completion in 1987
was $3.9 billion as measured in nominal terms (1987 dollars). These
cost increases are due in part to changes in Nuclear Regulatory
Commission (NRC) health and safety regulations after the Three Mile
Island accident. The remaining portion is generally due to inflation
over time and capitalization of interest during the delays. The
borrower defaulted in 1986, had its debt restructured in 1993, and
finally had its debt partially forgiven in September 1996. This
borrower is no longer in the RUS program.
In the early part of fiscal year 1997, another G&T borrower made a
lump sum payment of approximately $238.5 million in exchange for
forgiveness of its remaining $502 million loan balance. The G&T and
its six distribution cooperatives borrowed the $238.5 million from a
private lender, the National Rural Utilities Cooperative Finance
Corporation. The G&T had originally borrowed from RUS to build a
two-unit coal-fired generating plant and to finance a coal mine that
would supply fuel for the generating plant. The plant was built in
anticipation of industrial development from the emerging shale oil
industry. However, the growth in demand did not materialize, and
there was no market for the power. Although the borrower had its
debt restructured in 1989, it still experienced financial
difficulties due to a depressed power market. RUS and DOJ decided
that the best way to resolve the matter was to accept a partial lump
sum payment on the debt rather than force the borrower into
bankruptcy. The borrower and its member distribution cooperatives
are no longer in the RUS program.
ADDITIONAL LOSSES FROM
FINANCIALLY STRESSED G&T LOANS
ARE PROBABLE IN THE SHORT TERM
-------------------------------------------------------- Appendix VI:3
It is probable that RUS and DOJ will have additional loan write-offs
and therefore that the federal government will incur further losses
in the short term from loans to borrowers that have been identified
as financially stressed by RUS management. Borrowers considered
financially stressed have either defaulted on their loans, had their
loans restructured but are still experiencing financial difficulty,
declared bankruptcy, or have formally requested financial assistance
from RUS. According to RUS reports, about $10.5 billion of the $22.5
billion in G&T debt is owed by 13 financially stressed G&T borrowers,
as shown in table VI.1.\2 These borrowers are designated as A through
M in table VI.1. At RUS' request, we only identified, by name,
distressed borrowers that were in bankruptcy. Of these, four G&T
borrowers are in bankruptcy with about $7 billion in outstanding
debt. The remaining nine borrowers have investments in uneconomical
generating plants and/or have formally requested financial assistance
in the form of debt forgiveness from RUS.
Table VI.1
RUS Financially Stressed G&T
Cooperatives, as of September 30, 1996
(Dollars in millions)
Total debt
Borrower outstanding
-------------------------------------------------- ------------------
Borrower A\a,b $1,619.6
Borrower B 167.9
Borrower C 103.2
Borrower D\b 562.3
Borrower E\b 183.3
Borrower F\a,b 1,101.2
Borrower G\a,b 4,154.8
Borrower H\b 313.4
Borrower I\b 354.8
Borrower J 1,070.7
Borrower K 445.1
Borrower L 351.7
Borrower M\a 92.8
======================================================================
Total debt $10,520.8
----------------------------------------------------------------------
\a Cooperative in bankruptcy.
\b State regulated cooperative.
As indicated above, much of the financially troubled borrowers'
problems stem from their investments in nuclear-generating plants
that were completed late and over budget or in coal-fired generating
plants that were built to satisfy anticipated industrial growth that
did not materialize. The investments in nuclear plants by RUS
borrowers are for the most part minority interests in plants
constructed by one or more investor-owned utilities (IOUs).
According to RUS officials, among the reasons the plant investments
became uneconomical included rapidly increasing construction and
material costs, changing NRC regulations, and soaring interest rates.
Concurrent with these higher costs, projected demand for energy, in
many cases, did not materialize. These investments resulted in high
levels of debt and debt-servicing requirements, making power produced
from these plants expensive. Since cooperatives are nonprofit
organizations, there is little or no profit built into their rate
structure, which helps keep electric rates as low as possible.
However, the lack of retained profit generally means the cooperatives
have little or no cash reserves to draw upon. Thus, when cash flow
is insufficient to service debt, cooperatives must raise electricity
rates and/or cut other costs enough to service debt obligations. If
they are unable to do so, they may default on their government loans.
The following is a brief discussion of each of the 13 financially
stressed G&T borrowers:
Borrower A: Invested in construction of a nuclear plant that
experienced cost overruns and was never completed. The state
commission denied rate increases to cover the cost of the
cooperative's investment in the plant. The borrower defaulted on its
loan in 1984 and declared bankruptcy in 1985. The bankruptcy
proceedings have been in court for 12 years and are still not
completely resolved.
Borrower B: Made an investment in a nuclear plant that proved to be
uneconomical. While this borrower does not appear to be currently
experiencing financial difficulties, RUS considers them financially
stressed because they have formally requested financial assistance
due to impending competitive pressures.
Borrower C: Made an investment in a nuclear plant that proved to be
uneconomical. While this borrower does not appear to be currently
experiencing financial difficulties, RUS considers them financially
stressed because they have formally requested financial assistance
due to impending competitive pressures.
Borrower D: Uses primarily coal-fired generation. The borrower
overbuilt due to anticipated growth in electricity demand that did
not occur. During construction of a new plant, economic conditions
in the area changed and demand for electricity dropped, which
resulted in less revenue than predicted from the plant. The
cooperative was repeatedly denied rate increases to cover the cost of
its plants by the state commission.
Borrower E: Has a small percentage share in a nuclear plant that
proved to be uneconomical. The borrower has substantially higher
electricity rates than the IOUs in its region. The cooperative has
been denied rate increases to cover its losses by the state
commission. Although the borrower has had some of its debt
refinanced, it is still experiencing financial difficulties.
Borrower F: A G&T with primarily coal-fired generating plants that
overbuilt due to anticipated industrial growth related to two large
aluminum smelting companies. When aluminum prices dropped in the
early 1980s, the companies threatened to move their operations if the
cooperative did not lower electricity rates. The state commission
denied rate increases over the fear of losing these industries. RUS
restructured the borrower's debt in 1987 and 1990. The cooperative
filed for bankruptcy in September 1996 because its other creditors
were unwilling to negotiate.
Borrower G: Built a coal-fired plant and invested in a nuclear plant
in the mid-1970s which was completed late and experienced
construction cost overruns. Several factors contributed to the
cooperative's heavy debt, including excess electricity generation
construction resulting from overestimation of the demand for
electricity during the 1980s. The new capacity was intended to serve
a growth in demand that did not materialize. The state commission
disapproved a rate increase and instead lowered rates to a level
which precluded full debt service coverage. The commission also
refused to support a restructuring agreement that included a
significant RUS loan write-off.\3 The rate increase was requested by
the cooperative because of its high costs. The borrower filed for
bankruptcy in December 1994.
Borrower H: Invested in construction of a nuclear plant that proved
to be uneconomical. The project was completed 10 years late and over
budget. In addition, there was a dramatic drop in the demand for
electricity in the cooperative's service area and the state
commission would not allow rate increases to recover capital
investment. The borrower had its debt restructured in 1987; however,
it is requesting additional financial assistance due to anticipated
competitive pressure. A final settlement between RUS and the
borrower was reached in June 1997. The borrower will receive a
write-off of $165 million. The final payment and related debt
write-off will not occur until December 30, 1997.
Borrower I: Invested in a clean-burning coal plant that experienced
severe cost overruns. The borrower has substantially higher
electricity rates than the IOUs in its region. The state commission
has denied the cooperative's request for rate increases. The
borrower had some of its debt refinanced, but it is still
experiencing financial difficulty.
Borrower J: Invested in a nuclear plant that proved to be
uneconomical. The plant was completed late, which resulted in cost
overruns. As a result, the cooperative's wholesale power rates are
very high. The borrower has requested debt restructuring due to its
high cost of production and anticipated competitive pressure.
Borrower K: Invested in a nuclear plant that proved to be
uneconomical. The plant was completed late which resulted in severe
cost overruns. The cooperative's wholesale power rates are very
high, which has resulted in extreme unrest in the member distribution
cooperatives. The borrower is surrounded by IOUs with lower
wholesale rates. In addition, the borrower's system is very
difficult and expensive to maintain and experiences frequent power
outages. The borrower has requested financial assistance because of
anticipated competitive pressure.
Borrower L: Invested in a nuclear plant that proved to be
uneconomical. The plant was completed late, which resulted in severe
cost overruns. The cooperative has only five member distribution
cooperatives, which makes it difficult to cover its high production
costs. This borrower chose not to declare bankruptcy and is seeking
financial assistance. This borrower has refinanced its debt to lower
its interest rate, but is still experiencing financial difficulty and
has requested additional financial assistance.
Borrower M: Invested in a nuclear plant that proved to be
uneconomical. In addition, the cooperative had a stagnant customer
base in the 1980s. RUS tried to negotiate a restructuring agreement,
but the state commission denied two separate plans. In April 1996,
the borrower filed for bankruptcy.
In several instances noted above, state regulatory commissions denied
the rate increases necessary for the G&Ts to cover their costs and
service their RUS loans although several commissions had approved the
projects prior to construction. Seven of the 13 financially stressed
borrowers operate in states where regulatory commissions must approve
rate increases. These commissions may deny a request for a rate
increase if they believe such an increase will have a negative impact
on the region.
According to RUS and DOJ officials, in the Wabash Valley bankruptcy
case (borrower A), RUS recently received a legal decision which was
unfavorable to its interests and may encourage additional requests
for debt forgiveness from other RUS borrowers. In this case, the
effect of the court's decision was to allow the borrower to repay
only a portion of its RUS debt, even though RUS argued that such a
ruling sets a precedent that may allow other cooperatives to avoid
repaying their debts. RUS officials indicated that numerous
borrowers, including all of the financially stressed borrowers, have
already inquired about obtaining debt relief as a result of, among
other things, the unfavorable legal decision. Although several of
the financially stressed borrowers previously had their debts
restructured, some are again in severe financial trouble.
--------------------
\2 In our previous report, Rural Development: Financial Condition of
the Rural Utilities Service's Loan Portfolio (GAO/RCED-97-82, April
11, 1997), we noted 12 G&T and distribution borrowers that were
delinquent or in financial distress. However, in this report, we
discuss 13 financially stressed G&T borrowers identified by RUS
management. The primary difference is that this report does not
include one financially stressed distribution borrower, but did
include two borrowers that have officially requested financial
assistance as discussed following table VI.1.
\3 In states that regulate cooperatives, the state commission must
approve restructuring agreements between the cooperative and its
creditors.
SOME LOSSES FROM LOANS
CURRENTLY CONSIDERED VIABLE ARE
PROBABLE IN THE FUTURE
-------------------------------------------------------- Appendix VI:4
In addition to the financially stressed loans, RUS has loans
outstanding to G&T borrowers that are currently considered viable by
RUS but may become stressed in the future due to high costs and
competitive or regulatory pressures. We believe it is probable that
the federal government will eventually incur losses on some of these
G&T loans.
We believe the future viability of these G&T loans will be determined
based on their ability to be competitive in a deregulated market. In
order to assess the ability of RUS cooperatives to withstand
competitive pressures, we focused on the average revenue per
kilowatthour (kWh) of 33 of the 55 G&T borrowers with loans
outstanding of about $11.7 billion as of September 30, 1996. We
excluded 9 G&Ts that only transmit electricity and the 13 financially
stressed borrowers discussed above. Our analysis shows that for 27
of the 33 G&T borrowers, average revenue per kWh was higher in their
respective North American Electric Reliability Council (NERC)
regions\4 than IOUs and 17 of the 33 were higher than publicly-owned
generating utilities (POGs), as shown in figures VI.1 to VI.8. These
borrowers are designated as Borrowers 1 through 33 in figures VI.1 to
VI.8. The number of borrowers adds to more than 33 because some
overlap NERC regions and thus are shown more than once. The
relatively high average production costs indicate that the majority
of G&Ts may have difficulty competing in a deregulated market. RUS
officials told us that several borrowers have already asked RUS to
renegotiate or write off their debt because they do not expect to be
competitive due to high costs. RUS officials stated that they will
not write off debt solely to make borrowers more competitive.
As with the financially stressed borrowers, some of the G&T borrowers
currently considered viable have high debt costs because of
investments in uneconomical plants. In addition, according to RUS
officials, there are two unique factors that cause cost disparity
between the G&Ts and IOUs. One factor is the sparser customer
density per mile for cooperatives and the corresponding high cost of
providing service to the rural areas. A second factor has been the
inability to refinance higher cost Federal Financing Bank (FFB) debt
when lower interest rates have prevailed. However, RUS officials
said that recent legislative changes which enable cooperatives to
refinance FFB debt with a penalty may help align G&T interest rates
with those of the IOUs.
Figure VI.1: Average Revenue
per kWh for G&Ts in the
Southeastern Electric
Reliability Council (SERC)
Region
(See figure in printed
edition.)
Source: Developed by GAO based on data from RUS, preliminary
(unaudited) 1995 IOU data from the Energy Information Administration
(EIA), and POG data from the American Public Power Association
(APPA).
Figure VI.2: Average Revenue
per kWh for G&Ts in the
Southwest Power Pool (SPP)
Region
(See figure in printed
edition.)
Note: Borrower 31 serves both the Electric Reliability Council of
Texas (ERCOT) and SPP regions.
Source: Developed by GAO based on data from RUS, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
Figure VI.3: Average Revenue
per kWh for G&Ts in the
Electric Reliability Council of
Texas (ERCOT) Region
(See figure in printed
edition.)
Note: Borrower 31 serves both the ERCOT and SPP regions.
Source: Developed by GAO based on data from RUS, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
Figure VI.4: Average Revenue
per kWh for G&Ts in the
Mid-America Interconnected
Network (MAIN) Region
(See figure in printed
edition.)
Source: Developed by GAO based on data from RUS, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
Figure VI.5: Average Revenue
per kWh for G&Ts in the
Mid-Continent Area Power Pool
(MAPP) Region
(See figure in printed
edition.)
Note: Borrower 26 serves both the WSCC and MAPP regions.
Source: Developed by GAO based on data from RUS, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
Figure VI.6: Average Revenue
per kWh for G&Ts in the East
Central Area Reliability
Coordination Agreement (ECAR)
Region
(See figure in printed
edition.)
Source: Developed by GAO based on data from RUS, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
Figure VI.7: Average Revenue
per kWh for G&Ts in the Western
Systems Coordinating Council
(WSCC) Region
(See figure in printed
edition.)
Note: Borrower 26 serves both the WSCC and MAPP regions.
Source: Developed by GAO based on data from RUS, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
Figure VI.8: Average Revenue
per kWh for G&Ts in the Alaska
Systems Coordinating Council
(ASCC) Region
(See figure in printed
edition.)
Note: Comparison includes POGs only; data for IOUs unavailable for
ASCC.
Source: Developed by GAO based on data from RUS, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
In the short-term, G&Ts will likely be shielded from competition in
the wholesale market because of the all-requirements wholesale power
contracts between the G&Ts and their member distribution
cooperatives. With rare exceptions, these long-term contracts
obligate the distribution cooperatives to purchase all of their
respective power needs from the G&T. In fact, RUS requires the terms
of the contracts to be at least as long as the G&T loan repayment
period. However, wholesale power contracts have been challenged
recently in the courts by several distribution cooperatives because
of the obligation to purchase expensive G&T power. According to RUS
officials, one bankrupt G&T's member cooperatives are currently
challenging their wholesale power contracts in court in order to
obtain less expensive power. RUS officials believe that the
long-term contracts will come under increased scrutiny and potential
renegotiation or court challenges as other sources of less expensive
power become available.
Wholesale rates under these contracts are currently set by a G&T's
board of directors with approval from RUS. In states in which the
public utility commissions regulate cooperatives, the borrower must
file a request with the commission for a rate increase or decrease.
Several of the currently bankrupt borrowers were denied requests for
rate increases from state commissions. However, RUS officials
indicated they do not expect G&Ts to pursue rate increases as a means
to recover their costs because of the recognition of declining rates
in a competitive environment. RUS officials also acknowledge that
borrowers with high costs are likely to request debt forgiveness as a
means to reduce costs in order to be competitive in the future.
--------------------
\4 We used the 1995 NERC configuration because the latest available
data on average revenue per kWh by NERC region were for 1995; NERC's
configuration changed in 1996. See appendix III for a further
discussion.
RISK ASSESSMENT FOR SOUTHEASTERN,
SOUTHWESTERN, AND WESTERN
========================================================= Appendix VII
The three power marketing administrations (PMAs)\1 have about $5.4
billion of appropriated debt, and Western has an additional $1.6
billion of irrigation debt and $165 million of nonfederal debt. The
three PMAs market power that is substantially lower in cost than
nonfederal utilities, which indicates that, in the current operating
environment, they are competitively sound overall. However, all
three PMAs have one or a few projects or rate-setting systems with
problems that make risk of some loss to the federal government
probable. The federal government, to varying degrees, is at risk of
losing at least some of its investment in six projects/rate-setting
systems: the Russell Project (Southeastern), Truman Project
(Southwestern), Central Valley Project (Western), Pick-Sloan Program
(Western), Mead-Phoenix Transmission Line (Western), and Washoe
Project (Western).
--------------------
\1 The three PMAs are Southeastern Power Administration, Southwestern
Power Administration, and Western Area Power Administration.
THE FEDERAL GOVERNMENT'S
FINANCIAL INVOLVEMENT
------------------------------------------------------- Appendix VII:1
The federal government has substantial financial involvement in the
activities of the three PMAs. As shown in table VII.1, the federal
government's direct financial involvement, which consists of
appropriated debt and irrigation debt, is more than $7 billion, and
its indirect financial involvement, consisting of nonfederal debt at
Western, is about $165 million.
Table VII.1
Federal Government's Financial
Involvement in the Three PMAs as of
September 30, 1996 or September 30, 1995
(Dollars in millions)
Direct Indirect
---------------------- ----------
Appropriat Irrigation Nonfederal
PMA ed debt debt debt Total
-------------------------- ---------- ---------- ---------- ------
Southeastern $1,491\a $1,491
Southwestern 686\a 686
Western 3,217 $1,635 $165 5,017
======================================================================
Total $5,394 $1,635 $165 $7,194
----------------------------------------------------------------------
\a Because audited September 30, 1996, data were not available for
Southeastern and Southwestern at the time of our fieldwork, we used
September 30, 1995, appropriated debt balances for these two
entities. According to the PMAs, these balances did not
significantly change from 1995 to 1996.
DIRECT FINANCIAL INVOLVEMENT
----------------------------------------------------- Appendix VII:1.1
Appropriated debt consists of appropriations, which must be repaid
with interest, primarily used to construct the generating and
transmission facilities\2 related to the projects for which the three
PMAs market power.
Western also is responsible for repaying irrigation-related
construction costs on certain irrigation facilities, which we refer
to as irrigation debt. Some project-specific authorizing
legislation\3 provides for irrigation debt to be recovered primarily
by power revenues. This irrigation debt is to be repaid without
interest. Although irrigation debt is scheduled to be recovered with
power revenues, Western does not view irrigation debt as a power
cost. Therefore, when Western repays these amounts, neither the
costs nor the related revenues will be in its financial statements.
To the extent irrigation debt is repaid through electricity rates,
Western's power customers are subsidizing irrigators.
For direct involvement, the federal government would have a financial
loss if the PMAs were unable to repay principal or interest on debt
owed to the federal government.
--------------------
\2 Southeastern has no transmission facilities.
\3 Project-specific authorizing legislation determines how the costs
of constructing reclamation projects are allocated and how repayment
responsibilities are assigned among the projects' beneficiaries.
Collectively, the federal reclamation statutes that are generally
applicable to all projects and the statutes authorizing individual
projects are referred to as reclamation law. In implementing
reclamation law, the Bureau of Reclamation and Western are guided by
implementing regulations, administrative decisions of the Secretary
of the Interior and the Secretary of Energy, respectively, and
applicable court cases. Reclamation law provides for Western to use
its power revenues to repay Treasury a certain portion of the capital
costs allocated to completed irrigation facilities that are
determined by the Secretary of the Interior to be beyond the ability
of the irrigators to repay (irrigation assistance).
INDIRECT FINANCIAL
INVOLVEMENT
----------------------------------------------------- Appendix VII:1.2
The federal government's indirect financial involvement, which
consists of nonfederal debt related to certain projects marketed by
Western, is about $165 million. The nonfederal debt is capital
provided by Western's customers (primarily through the issuance of
bonds) to finance capital improvement projects. The customers pay
the debt service cost, and Western records the bond proceeds as a
liability and records interest expense. Western then bills the
customers for the production costs of electricity, including the debt
service, and credits the customers for the debt service costs.
Essentially, this arrangement results in customers directly paying
for capital projects rather than paying for them indirectly through
rates.
For indirect involvement, the federal government would have a
financial loss if it incurred unreimbursed costs in an effort to
prevent Western from breaching agreements to service its nonfederal
debt.
THE THREE PMAS ARE
COMPETITIVELY SOUND OVERALL
------------------------------------------------------- Appendix VII:2
The three PMAs market power that is substantially lower in cost than
power sold by nonfederal utilities, which indicates that they are
currently competitively sound overall. The PMAs' low average revenue
per kilowatthour (kWh)\4 are the result of their cost recovery
structure,\5 other inherent cost advantages, and management actions
to control costs. We also noted some disadvantages that the three
PMAs experience because they are federal entities.
--------------------
\4 See appendix III for a discussion of average revenue per kWh as an
indicator of power production costs.
\5 Cost recovery structure refers to the three PMAs' ability to
exclude certain costs from rates, called "unrecovered costs." Certain
unrecovered costs may be recoverable in the future.
AVERAGE REVENUE PER KWH HAS
BEEN SUBSTANTIALLY LOWER
THAN NONFEDERAL UTILITIES
----------------------------------------------------- Appendix VII:2.1
Overall, the three PMAs' average revenue per kWh were more than 40
percent below those of other nonfederal utilities for 1995.
Moreover, GAO previously found\6 that the three PMAs' average revenue
per kWh were consistently 40 percent or more below nonfederal
utilities for the years 1990 through 1994. This indicates that the
three PMAs, overall, are fairly well-positioned for an increased
competitive environment resulting from deregulation. However, the
three PMAs' competitive position could be eroded if they are required
to recover additional power-related costs and/or if increased
competition in the electric utility industry causes wholesale and
retail electricity rates to significantly drop. Figure VII.1
illustrates the difference between the average revenue per kWh for
these PMAs compared to investor-owned utilities (IOUs) and
publicly-owned generating utilities (POGs) for 1995 in the primary
North American Electric Reliability Council (NERC) regions in which
the PMAs operate.\7 See appendix III for a map of the NERC regions of
the contiguous United States.
Figure VII.1: Average Revenue
per kWh of Wholesale Power
Sold, 1995
(See figure in printed
edition.)
Legend
SEPA/SERC = Southeastern/Southeastern Electric Reliability Council
SWPA/SPP = Southwestern/Southwest Power Pool
WAPA/WSCC = Western/Western Systems Coordinating Council
Source: Developed by GAO based on data from the PMAs' 1995 annual
reports, preliminary (unaudited) 1995 IOU data from the Energy
Information Administration (EIA), and POG data from the American
Public Power Association (APPA).
In addition to an overall assessment of the PMAs' costs, we compared
the average revenue per kWh of each of the three PMAs' rate-setting
systems\8 to IOUs and POGs in each system's geographic area. Except
for a few rate-setting systems at Western and Southeastern, the three
PMAs' average revenue per kWh by rate-setting system are about 40 to
50 percent below those of other nonfederal utilities for 1995.
Figures VII.2 through VII.9 show a comparison of average revenue per
kWh for each of the PMAs' 17 rate-setting systems to the relevant
NERC region.\9 This detailed comparison is particularly relevant
because PMA rates are set at a rate-setting system level. Some
rate-setting systems market power in more than one NERC region and
thus are shown in more than one figure.
Figure VII.2: Comparison of
Average Revenue per kWh by
Southeastern Rate-setting
System for the SERC Region,
1995
(See figure in printed
edition.)
Legend
GA/AL/SC = Georgia/Alabama/South Carolina system.
Source: Developed by GAO based on data from Southeastern's 1995
annual report, preliminary (unaudited) 1995 IOU data from EIA, and
POG data from APPA.
Figure VII.3: Comparison of
Average Revenue per kWh by
Southwestern Rate-setting
System for the Southwest Power
Pool (SPP) Region, 1995
(See figure in printed
edition.)
Source: Developed by GAO based on data from Southwestern's 1995
annual report, preliminary (unaudited) 1995 IOU data from EIA, and
POG data from APPA.
Figure VII.4: Comparison of
Average Revenue per kWh by
Southwestern Rate-setting
System for the Electric
Reliability Council of Texas
(ERCOT) Region, 1995
(See figure in printed
edition.)
Source: Developed by GAO based on data from Southwestern's 1995
annual report, preliminary (unaudited) 1995 IOU data from EIA, and
POG data from APPA.
Figure VII.5: Comparison of
Average Revenue per kWh by
Southwestern Rate-setting
System for the Mid-Atlantic
Interconnected Network (MAIN)
Region, 1995
(See figure in printed
edition.)
Source: Developed by GAO based on data from Southwestern's 1995
annual report, preliminary (unaudited) 1995 IOU data from EIA, and
POG data from APPA.
Figure VII.6: Comparison of
Average Revenue per kWh by
Western Rate-setting System for
the Western Systems
Coordinating Council (WSCC)
Region, 1995
(See figure in printed
edition.)
Note: As discussed later in this appendix, Western is planning to
reduce rates for the Central Valley Project (CVP).
Source: Developed by GAO based on data from Western's 1995 annual
report and appendix to the 1996 annual report, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
Figure VII.7: Comparison of
Average Revenue per kWh by
Western Rate-setting System for
the SPP Region, 1995
(See figure in printed
edition.)
Source: Developed by GAO based on data from Western's 1995 annual
report and appendix to the 1996 annual report, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
Figure VII.8: Comparison of
Average Revenue per kWh by
Western Rate-setting System for
the Mid-Continent Area Power
Pool (MAPP) Region, 1995
(See figure in printed
edition.)
Source: Developed by GAO based on data from Western's 1995 annual
report and appendix to the 1996 annual report, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
Figure VII.9: Comparison of
Average Revenue per kWh by
Western Rate-setting System for
the ERCOT Region, 1995
(See figure in printed
edition.)
Source: Developed by GAO based on data from Western's 1995 annual
report and appendix to the 1996 annual report, preliminary
(unaudited) 1995 IOU data from EIA, and POG data from APPA.
--------------------
\6 Power Marketing Administrations: Cost Recovery, Financing, and
Comparison to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
1996).
\7 The latest data available for all entities except Western were for
1995; Western had both 1995 and 1996 data. We used Western's 1995
data in order to ensure comparability to IOUs and POGs within the
given time period. However, it should be noted that Western's
overall average revenue per kWh decreased from 1.87 in 1995 to 1.65
in 1996. All of Western's projects' average revenue per kWh
decreased in 1996 except Central Arizona (increased from 2.13 to
2.34), Washoe (increased from .99 to 1.02), and Falcon-Amistad
(increased from 1.82 to 2.68); all three projects' average revenue
per kWh were still more than 33 percent below IOUs and POGs in their
respective regions. However, in the case of Washoe, average revenue
per kWh may not be reflective of power production costs because not
all costs are being recovered through rates. This also may be the
situation at several other projects or rate-setting systems with
financial problems discussed later in this appendix.
\8 A rate-setting system consists of one or more power projects.
\9 We used the 1995 NERC configuration because the latest available
data on average revenue per kWh by NERC region were for 1995. NERC's
configuration changed in 1996. See appendix III for a further
discussion.
COST RECOVERY STRUCTURE AND
INHERENT ADVANTAGES
CONTRIBUTE TO LOW-COST POWER
----------------------------------------------------- Appendix VII:2.2
As noted in volume 1 of this report and in our September 1996
report,\10 the three PMAs do not recover all costs associated with
producing and marketing federal hydropower. These unrecovered costs
include net financing costs, Civil Service Retirement System (CSRS)
pension and postretirement health benefits, certain construction
costs, power-related costs assigned to incomplete irrigation projects
at Pick-Sloan, certain environmental costs legislatively precluded
from recovery, and deferred operations and maintenance (O&M) and
interest expenses. As we noted in volume 1 of this report, the PMAs
are generally following applicable laws and regulations and believe
that some of these costs, including construction and deferred O&M and
interest expense, are recoverable through future rates. If the PMAs
are required to recover some or all of the above unrecovered costs,
which we estimate totaled about $185 million for fiscal year 1996,
their ability to remain competitive may be impaired and the risk of
future financial loss to the federal government increased.
The three PMAs have two other key inherent advantages that enhance
their competitive positions. First, the three PMAs market power
generated mainly by hydroelectric plants built decades ago, while
other utilities are primarily dependent on coal and nuclear
generating plants. Table VII.2 shows the contrast between the three
PMAs and other utilities in the percentage of power coming from
different generating sources.
Table VII.2
Percentage of Net Power Generation for
the PMAs and Other Utilities, 1996
Net power generated (percent)
---------------------------------------
Coal Nuclear Gas Hydro Other
----------------------------- ------ ------- ------ ------ ------
Three PMAs 6.6\a 0 0 93.4 0
Other utilities 57.5 24.2 9.7 6.1 2.5
----------------------------------------------------------------------
\a A relatively small amount of electricity marketed by Western is
produced from coal-generating units.
Source: Energy Information Administration.
The hydroelectric plants that generate the power marketed by the PMAs
have significant cost advantages over coal and nuclear generating
plants. For example, the PMAs' hydroelectric plants, many of which
were built 30 to 60 years ago, had relatively low construction costs.
To show the relatively low capital cost of the hydropower plants,
which contributes to the PMAs low average revenue per kWh, we
compared the three PMAs' investment in utility plant per megawatt of
capacity for these plants to those of other utilities. This ratio
depicts the relative costs of building generating plants. As shown
in figure VII.10, the three PMAs have substantially less invested in
plant than the other utilities. Southeastern has substantially more
invested in plant than the other two PMAs because the Russell Project
has incurred capital costs of more than $500 million as of September
30, 1996, with no corresponding increase in generating capacity from
the project's nonoperational portion.
Figure VII.10: Investment in
Utility Plant per Megawatt of
Generating Capacity, 1995
(See figure in printed
edition.)
Source: Developed by GAO based on data from the PMAs' 1995 annual
reports and 1995 POG and IOU data from EIA.
Compared to other utilities, the lower investment in PMA-related
hydroelectric plants is partly the result of lower construction costs
when these plants were built 30 to 60 years ago compared to more
recent construction costs. Unlike the three PMAs and operating
agencies, IOUs build new capacity to meet the future needs of
customers. Many IOU and POG nuclear plants that were completed and
are operating had significant capital construction costs, which are
at least partly due to stringent Nuclear Regulatory Commission
regulations. Utilities with coal plants must comply with the Clean
Air Act, which requires significant investments in pollution control
equipment for many plants. The PMAs' relatively low investment in
utility plant results in a large cost advantage.\11 Appendix II
describes the methodology used for computing the ratios in figure
VII.10.
Another major reason that hydroelectric plants result in lower power
production costs is the cost of fuel. This is particularly important
when comparing hydro plants to coal plants. The cost of coal is a
major operating expense for most other utilities. Nuclear fuel is
also a significant cost, although not nearly as large a factor as
coal. In 1995, POGs' fuel costs represented about 11 percent of
operating revenues, while IOUs' fuel costs represented about 16
percent of operating revenues. The PMAs, on the other hand, have the
benefit of marketing power from hydroelectric plants, which do not
have an associated fuel cost.\12
The three PMAs' reliance on hydroelectric generation can also be a
disadvantage in poor water years. Because of the reliance on water,
the three PMAs' revenues can vary considerably and in some years are
not sufficient to cover operating and interest expenses. As a
result, the three PMAs are allowed to defer O&M and interest expense
payments in years when revenue is not sufficient to cover these
costs. Each of the three PMAs has at one time or another had to
defer O&M and interest expense payments because of poor water
conditions.\13
Another key inherent advantage for the three PMAs is that, as federal
agencies, they generally do not pay taxes. In contrast, IOUs do pay
taxes. According to EIA, in 1995, IOUs paid taxes averaging about 14
percent of operating revenues. This average varies significantly
from state to state due to differing state and local government tax
laws. Taxes paid by IOUs include federal and state income taxes,
real and personal property taxes, corporate franchise taxes, invested
capital taxes, and municipal license taxes.
POGs, as publicly owned utilities, typically do not pay income taxes
because they are units of state or local governments. However, many
POGs do make payments in lieu of taxes to local governments. A
study\14 of 670 POGs showed that POGs' median net payments and
contributions as a percent of electric operating revenue for 1994
were 5.8 percent. With the exception of the Boulder Canyon Project,
PMAs generally do not make payments in lieu of taxes to state or
local governments. The Boulder Canyon Adjustment Act of 1940
requires annual payments to the states of Arizona and Nevada. In
1995, $600,000, 1.2 percent of the project's operating revenue, was
paid to these states in lieu of taxes.
--------------------
\10 Power Marketing Administrations: Cost Recovery, Financing, and
Comparison to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
1996).
\11 Our analysis excluded nuclear plants that are mothballed and thus
provide no capacity while resulting in significant capital costs.
Mothballed nuclear plants can be either incomplete or completed
plants that have had construction terminated or have been shut down
either temporarily or permanently. Under generally accepted
accounting principles, these costs are either written off or, if
deemed allowable by the applicable regulator, are classified as
"regulatory assets" and included in rates through amortization.
Inclusion of these regulatory assets would have increased the POG and
IOU investment.
\12 As noted in table VII.2, a relatively small amount of electricity
marketed by Western is produced from coal.
\13 The flexibility to defer O&M and interest expense enhances the
three PMAs' ability to compete in a deregulated environment.
\14 1994 Payments and Contributions by Public Power Distribution
Systems to States and Local Government, American Public Power
Association, March 1996.
MANAGEMENT ACTIONS AND THE
NATURE OF CUSTOMER CONTRACTS
CONTRIBUTE TO THE OVERALL
SOUND COMPETITIVE POSITION
OF THE THREE PMAS
----------------------------------------------------- Appendix VII:2.3
The three PMAs have taken action to enhance their ability to compete.
However, because the U.S. Army Corps of Engineers (Corps) and the
Bureau of Reclamation (Bureau) operate federal projects, many capital
and operating costs are beyond the control of the PMAs.
Southeastern, unlike Southwestern and Western, does not own any
transmission lines and thus has only a small amount of controllable
costs. The main cost under Southeastern's control is staffing, and
management has held staffing at the PMA steady over the past few
years.
At Southwestern, management recently reorganized and began to
downsize staff to reduce costs. Southwestern management has also
begun to benchmark leaders in the electric utility industry. This
benchmarking effort is expected to help Southwestern identify ways to
become more efficient and effective, reduce costs in the future, and
identify appropriate performance measures that can be used to compare
Southwestern's performance to its competition.
At Western, management has undertaken a substantial downsizing of
staff and initiated other transformation efforts to prepare for
competition. According to Western officials, Western is downsizing
staff by about 25 percent and they expect this effort to result in
annual savings of about $25 million. In addition, Western has
redesigned jobs, instituted manager training, streamlined procedures,
and continued to work on upgrading its financial management system to
provide better business information. Western has also hired a
benchmarking manager and formed a team to track its position relative
to its competitors and to develop benchmarking techniques as part of
its streamlining efforts.
The nature of the contracts with customers is also currently an
advantage to the three PMAs. According to the PMAs, the contracts
are cost-based, which means that if the PMAs' costs rise they have a
mechanism to pass those costs along to customers. These long-term
contracts, lasting up to 20 years, do not specify rates. Instead,
the contracts specify that the customers will pay the rates in effect
at the time. If the PMAs raise rates, the customers have the option
of cancelling their contracts, generally within 1 year of a notice of
a rate increase. These contracts are an advantage for the PMAs as
long as their rates are below market because they can pass rising
costs along to customers and still be competitive. However, should
the three PMAs' rates get close to market rates, the customers'
ability to cancel contracts could work to the three PMAs'
disadvantage.
The PMAs also have certain disadvantages compared to nonfederal
utilities that could impact their competitiveness. For example,
Western is required to recover approximately $1.635 billion related
to construction costs on completed irrigation facilities.\15 In
addition, Western is required to recover through rates the cost of
the Hoover Dam Visitor Center totaling an estimated $124 million.
--------------------
\15 Reclamation law provides for Western to repay certain portions of
capital costs allocated to irrigation purposes which are determined
to be beyond the ability of the irrigators to repay.
RISK OF FUTURE LOSSES FROM
INDIVIDUAL RATE-SETTING
SYSTEMS/PROJECTS IS PROBABLE
------------------------------------------------------- Appendix VII:3
Although the three PMAs are currently competitively sound overall, we
identified situations at one or a few projects or rate-setting
systems at each of the three PMAs that, taken as a whole, indicate
that it is probable that the federal government will incur some
future financial losses from one or more of the three PMAs' projects.
The federal government, to varying degrees, is at risk of losing at
least some of its investment in six projects/rate-setting systems:
the Russell Project (Southeastern), Truman Project (Southwestern),
CVP (Western), Pick-Sloan Program (Western), Mead-Phoenix
Transmission Line (Western), and Washoe Project (Western). The
issues related to each project, grouped by PMA, are discussed below.
SOUTHEASTERN
----------------------------------------------------- Appendix VII:3.1
To date, about one-half of the cost of constructing the Richard B.
Russell Project\16 has been excluded from rates paid by power
customers because the project has never operated as intended. In
addition, interest associated with these capital costs is not paid to
Treasury each year. Instead, interest--an estimated $29.9 million
for fiscal year 1996--is capitalized and added to the construction
work-in-progress (CWIP) balance annually. It is unclear whether the
project will ever become fully operational. However, if the
nonoperational portion of the project never operates as intended, it
is probable that the federal government will not recover these
construction and interest costs.
This project, located in the Savannah River between Georgia and South
Carolina, is positioned between two existing dams and was built
virtually exclusively for the generation of hydropower. Under the
Corps' tentative cost allocation, 99 percent of Russell's original
construction costs and 93 percent of its annual O&M expenses are
allocated to power. The project, which enjoyed broad support from
electric utilities in North Carolina, South Carolina, and Georgia
because of its potential to generate low cost power, was authorized
by the Flood Control Act of 1966 and construction began in 1976.
The Russell Project has four operational conventional generating
units that provide 300,000 kilowatts of capacity and four
nonoperational pumping units intended to provide another 300,000
kilowatts of capacity.\17 The last of the four conventional units
came on-line in 1986, and the costs associated with these units went
into Southeastern's costs for recovery. However, because of
litigation over excessive fish kills, the four pumping units that
were completed in 1992 have never been allowed to operate
commercially. As a result, the costs associated with them have been
left in a CWIP account and have not been included in rates. Interest
is not paid to Treasury each year on the federal government's
investment in the nonoperational portion of the project; instead, it
is capitalized and added to the CWIP balance. We estimate that the
balance in the CWIP account was about $518 million at September 30,
1996. Since 1996 audited financial statements for Southeastern were
not available at the time of our review, we estimated the September
30, 1996, figure by taking the CWIP balance at September 30,
1995--$488 million--and adding capitalized interest of $29.9 million,
which we estimated based on the 6.125 percent interest rate
applicable to the Russell Project.\18
If the nonoperational portions of the Russell Project are allowed to
operate commercially in the near future and the costs go into rates,
Southeastern officials estimate that a rate increase of about 25
percent to customers of the Georgia-Alabama-South Carolina system
would be necessary. This projected rate increase would be necessary
for two reasons. First, interest expense related to the
nonoperational units--which will be more than $30 million in fiscal
year 1997--would be included in rates rather than capitalized.
Second, the $518 million currently in CWIP would also be included in
Southeastern's costs for recovery from power customers. This
situation poses a challenge to Southeastern in a competitive
electricity market. According to a representative of the
Southeastern Federal Power Customers, a customer group that
represents most of Southeastern's customers, power from the
Georgia-Alabama-South Carolina system would remain competitive even
after a 25 percent rate increase. The customer group's view,
combined with the current production cost advantage\19 of the
Georgia-Alabama-South Carolina system, of which Russell is a part,
indicate that the system should be able to remain competitive if the
nonoperational pumping units are allowed to operate commercially and
costs are put into rates in the near future. Under this scenario, we
believe the risk of loss to the federal government is remote.
However, the longer the eventual operation of the Russell project is
delayed, the greater the costs that will have to be recovered through
rates and the greater the potential impact on rates. If full
deployment of the nonoperational units continues to be delayed, at
some point the price of the power may not be competitive. We believe
this poses a reasonably possible risk of future loss to the federal
government.
Litigation over the Russell Project is still pending. Southeastern's
management believes that the Russell Project is still viable and that
the litigation will be settled by allowing the project to operate
commercially. However, under current policy guidance, if the
nonoperational units at Russell are not allowed to be put into
commercial service, the power customers will not be required to repay
this large federal investment.\20 We believe that under this
scenario, it is probable that the federal government will lose its
entire $518 million investment.\21
--------------------
\16 The Richard B. Russell Project was originally named the Trotters
Shoals Dam.
\17 The pumping units are designed to allow water, after it has
passed through generating units, to be pumped back into the reservoir
during periods of low demand for electricity. Then, the water can be
used to produce power during periods of high demand for electricity.
\18 To estimate the net interest cost, we used the Russell Project
interest rate of 6.125 rather than Southeastern's overall weighted
average interest rate on outstanding appropriated debt of 4.4 percent
for fiscal year 1995.
\19 As shown in figure VII.2, the Georgia-Alabama-South Carolina
system's average revenue per kWh for 1995 was 2.88 cents per kWh,
compared to 4.37 cents and 5.09 cents for IOUs and POGs,
respectively, in the SERC region.
\20 This refers to policy guidance contained in Department of Energy
(DOE) order RA6120.2 through which the recovery of power-related
costs has been implemented by the Secretary of Energy.
\21 This $518 million at risk represents about 35 percent of the
federal government's financial involvement of $1,491 million at
Southeastern.
SOUTHWESTERN
----------------------------------------------------- Appendix VII:3.2
A situation similar to Russell exists at the Harry S. Truman Dam and
Reservoir, which is located in the Osage River in Missouri.\22
Designed originally for flood control, hydropower and recreation were
later added as authorized project purposes. Construction of the
Truman project began in October 1964 and it was placed in service
(for flood control and recreation) in November 1979. The in-service
dates for hydropower generating units range from January 1980 to
September 1982.
The Truman Project has six generating units that could provide
160,000 kilowatts of capacity and are also designed to operate as
pumping units. However, because of design problems and fish kills
caused by the pumping units, the Truman project has never been
operated at its 160,000 kilowatt capacity. Instead, only 53,300
kilowatts have been declared to be in commercial operation and use of
the pump-back facilities has never been commercially implemented. As
a result, the Corps determined that it would be inappropriate to
recover through power rates the costs associated with the units that
have not been used commercially.
The Corps prepared an interim cost allocation for this project which
accounted for the Truman Project not being fully operational.
Southwestern petitioned the Federal Energy Regulatory Commission
(FERC) to have the cost of the nonproducing portion of the assets
deferred from inclusion in power rates until the project becomes
fully operational. FERC concurred as part of its approval of
Southwestern's 1989 power rates. As a result of FERC's decision,
Southwestern has deferred the inclusion of the estimated amount of
the costs associated with the nonoperational units in Southwestern's
reimbursable share of the project's costs. Thus, $31 million has
been deferred from recovery through power rates, reducing the total
to be repaid from $158 million to $127 million.\23 This deferral is
accomplished through an adjustment to Southwestern's appropriated
debt each year. According to Southwestern officials, the $31 million
adjustment is not a permanent elimination of these costs from
Southwestern's appropriated debt; these costs will be included in
rates and recovered from power customers if the Harry S. Truman
facility operates as designed. Corps officials also told us that the
Corps is making progress in addressing the design problems. The
Corps has modified four of the Truman units and expects to complete
modifications to the other two units by about mid-January, 1998.
According to Corps officials, the modification program should
increase Truman's unit availability. However, the issue of fish
kills caused by the pumping units has not been resolved and
associated capacity has not been restored. In contrast to the
situation at Russell, where interest is capitalized on the CWIP
balance and not paid to Treasury annually, Southwestern has paid
interest on the $31 million deferral through fiscal year 1996.
Unless there is a change in the status of the pump-back units, which
we believe is unlikely given the time frame they have been
inoperable, it is probable that the federal government will lose the
$31 million\24 that has been deferred from rates. However, if the
pump-back units are allowed into commercial operation and placed into
rates, we believe that Southwestern's relative cost advantage\25
indicates that it could absorb the $31 million deferral without a
significant impact on rates. Additionally, since Southwestern pays
annual interest on the deferred Truman costs, the risk is not
increasing over time due to an increasing balance that would have to
be repaid if the units become operational in the future. If the
units do become operational, we believe the risk of future losses to
the federal government is remote.
--------------------
\22 The Harry S. Truman Project was originally named the Kaysinger
Bluff Dam and Reservoir. Public Law 92-267 changed the name of the
project to the Harry S. Truman Dam and Reservoir on May 26, 1970.
\23 According to Southwestern officials, the deferral does not affect
O&M costs since all power-related O&M expenses are paid annually.
\24 This $31 million at risk represents about 5 percent of the
federal government's financial involvement of $686 million at
Southwestern.
\25 As shown in figure VII.3, the Integrated System's (of which
Truman is a part) average revenue per kWh for 1995 was 1.34 cents per
kWh, compared to 2.73 cents and 3.48 cents for IOUs and POGs,
respectively, in the SPP region.
WESTERN
----------------------------------------------------- Appendix VII:3.3
CENTRAL VALLEY PROJECT
--------------------------------------------------- Appendix VII:3.3.1
The Central Valley Project (CVP), which had outstanding appropriated
debt of about $267 million as of September 30, 1996, and incurred a
$24 million loss in fiscal year 1996,\26
faces competition in the California market from low-cost producers
and others selling surplus power. Western officials, who market CVP
power, have responded to this competition by cutting rates by about
26 percent in fiscal year 1996 and establishing a plan to further
reduce rates for CVP power by exercising escape clauses in contracts
to purchase power for resale to CVP customers.\27 According to
Western officials, the power they are currently purchasing is priced
higher than CVP's actual production costs, and eliminating the power
purchases will enable them to reduce CVP's rates and be competitive.
Western officials said that they have studied the CVP purchase power
contracts, determined when they can exercise the escape clauses, and
assessed the resulting rate reductions that can be implemented over
the next few years. The officials said they were confident that CVP
can price its power competitively by eliminating the contracts to
purchase relatively expensive power.
A representative of a group of CVP customers confirmed that CVP power
is presently priced above market and agreed with the Western
officials' assessment that by eliminating the contracts to purchase
power CVP can price its power competitively. The representative
noted that no customers have cancelled contracts with CVP because
they believe that the current competitive difficulties can be
resolved. However, he also said that the customers that he
represents would prefer that Western officials in the future focus on
merely selling CVP's output rather than on entering into contracts to
purchase power in an effort to meet customers' demand for power.
Whether Western management's efforts to increase CVP's
competitiveness will be successful is uncertain. Moreover, the
implementation of the Central Valley Project Improvement Act (CVPIA)
of 1992 is likely to impact the availability of water for power
generation. CVPIA strengthened existing fish and wildlife project
purposes by adding fish and wildlife mitigation, protection, and
restoration as an authorized purpose of CVP. This legislation
emphasized the safeguarding of fish and wildlife. As a result, less
water may be available for irrigation, power generation, municipal
and industrial use, and other purposes. To the extent that power
revenues are reduced as a result of the implementation of CVPIA, the
uncertainty over the repayment of the federal government's investment
in hydropower facilities at CVP increases. In addition, according to
Western officials, when the reallocation of the water occurs, there
will be a reallocation of substantial costs to power. Reallocating
costs to power when power revenues are expected to be reduced would
further increase the uncertainty surrounding the repayment of the
federal government's investment in hydropower facilities at CVP.
Moreover, the amount of water available for hydropower production at
CVP may be further reduced as a result of changes in the flow of
water from the Trinity River. The 1984 Trinity River Basin Fish and
Wildlife Management Act provided for a program to restore fish and
wildlife populations to levels that existed just prior to the
construction of the Trinity River and Lewiston dams in Western's
Trinity River Division in 1963, which diverted a large portion of the
Trinity River's water to the Central Valley of California. We
believe, and PMA officials have agreed, that the changes in the
Trinity River water flow resulting from the restoration program may
increase the risk of loss to the federal government from CVP. These
uncertainties, combined with the competition CVP faces, lead us to
believe that it is reasonably possible that the federal government
will lose some of its $267 million investment\28 in CVP.
--------------------
\26 The $24 million net loss is an accrual-based net loss; CVP was
able to meet its cash flow requirements in fiscal year 1996.
\27 According to Western officials, CVP is currently in a formal
rate-making process for a rate reduction effective October 1, 1997,
that will reduce the CVP rate to 2.06 cents per kWh. Western
officials state that further reductions are planned in fiscal year
1999 to 1.96 cents per kWh and in fiscal year 2001 to 1.86 cents per
kWh.
\28 This $267 million at risk represents about 5 percent of the
federal government's financial involvement of $5,017 million at
Western.
PICK-SLOAN MISSOURI BASIN
PROGRAM
--------------------------------------------------- Appendix VII:3.3.2
The Pick-Sloan Missouri Basin Program (Pick-Sloan) is a comprehensive
plan to manage the water and hydropower resources of the Missouri
River Basin.\29 Substantial capital costs for Pick-Sloan hydropower
facilities and water storage reservoirs have been allocated to
authorized irrigation facilities that are incomplete and infeasible.
Western is currently using water to generate power that would have
been used by irrigators if the irrigation projects had been
completed. If the costs had been allocated based on actual use, they
would have been allocated primarily to power and recovered through
power rates within 50 years, with interest. However, as long as the
costs are allocated to incomplete or infeasible irrigation projects,
they will likely never be recovered. Since all but one of the
irrigation facilities are not expected to be completed, the capital
costs assigned to the others will not be repaid unless the Congress
approves a change in the cost allocation methodology used to
distribute costs to the various program purposes or deauthorizes the
incomplete or infeasible irrigation facilities.\30 In May 1996,\31 we
estimated that these capital costs were about $454 million as of
September 30, 1994. Since these costs increased by an average of
nearly $5 million annually between fiscal year 1987 and fiscal year
1994, we estimate that the costs totaled about $464 million as of
September 30, 1996. Under the current repayment criteria, it is
probable that Western will not be required to recover the principal
or any interest on the $464 million\32
investment.
--------------------
\29 Pick-Sloan encompasses those parts of Colorado, Iowa, Kansas,
Minnesota, Missouri, Montana, Nebraska, North Dakota, South Dakota,
and Wyoming from which water drains into the Missouri River.
\30 Any changes made regarding the program's power and irrigation
purposes may necessitate reviewing other aspects of the
agreements--specifically, the agreements involving areas that
accepted permanent flooding from dams in anticipation of the
construction of irrigation projects that are now not likely to be
constructed.
\31 Federal Power: Recovery of Federal Investment in Hydropower
Facilities in the Pick-Sloan Program (GAO/T-RCED-96-142, May 2,
1996).
\32 This $464 million at risk represents about 9 percent of the
federal government's financial involvement of $5,017 million at
Western.
MEAD-PHOENIX TRANSMISSION
LINE
--------------------------------------------------- Appendix VII:3.3.3
Another project with questionable financial viability is the
Mead-Phoenix Transmission Line. Mead-Phoenix was recently added to
the Pacific Northwest-Pacific Southwest Intertie (Transmission)
Project intended to increase power transmission capability between
central Arizona, southern Nevada, and southern California. This
transmission project was a joint venture between Western and 15 other
utilities and began operation in April 1996. Western's share of the
total project's costs is about 34 percent. Western's portion of the
cost of the project, including capitalized interest, is about $94.7
million. Western officials said that, in 1990 and 1993, prospective
customers of the Mead-Phoenix line indicated that their demand for
power from the line significantly exceeded Western's share of
capacity. However, anticipated demand for power from the line later
dropped precipitously and it is unclear whether Western will be able
to successfully market its entire transmission capacity.
In March 1996 and again in September 1996 testimony before the
Subcommittee on Water and Power Resources, House Committee on
Resources,\33 Western officials said that they were aggressively
marketing the remainder of the line's capacity. The Western
officials indicated that if the project does not achieve the level of
sales assumed in developing the transmission charges, they will
initiate a new rate process to assure recovery of project costs.
Western officials said that they were considering blending the
Mead-Phoenix Transmission Line's rates into the overall rates of the
Pacific Northwest-Pacific Southwest Intertie Project, of which it is
a part. The Western officials asserted that doing this would make
the Mead-Phoenix costs recoverable and that they had successfully
done similar types of consolidations in the past. However, to date,
the financial results have been discouraging. From April 1996, when
it was placed in service, through January 1997, Mead-Phoenix has
generated revenues of only about $71,319 while incurring O&M and
interest expenses of nearly $7.3 million, resulting in a net loss of
about $7.2 million. The transmission line's poor financial
performance raises serious questions about its financial viability.
If the consolidation under consideration cannot be successfully
implemented, we believe it is probable that the federal government
will lose at least some of its $94.7 million\34 investment in
Mead-Phoenix. Even if the consolidation can be completed, there is
no indication that the demand for power from the line will increase
or that Western will be able to successfully market its entire
transmission capacity, resulting in a reasonably possible risk of
future loss to the federal government.
--------------------
\33 Western Area Power Administration (WAPA) Construction and
Maintenance Activities and Bureau of Reclamation Power Facilities
Management, Hearing Before the Subcommittee on Water and Power
Resources, House Committee on Resources, 104th Cong., 2nd Sess.
(March 19, 1996), and Statement of Mr. J. M. Shafer,
Administrator, Western Area Power Administration, United States
Department of Energy, Hearing Before the Subcommittee on Water and
Power Resources, House Committee on Resources, 104th Cong., 2nd Sess.
(September 19, 1996).
\34 This $94.7 million at risk represents about 2 percent of the
federal government's financial involvement of $5,017 million at
Western.
WASHOE PROJECT
--------------------------------------------------- Appendix VII:3.3.4
The Washoe Project (Stampede Powerplant), located in west-central
Nevada and east-central California, is not generating sufficient
revenue to cover annual power-related operating expenses and interest
or to repay the federal investment. In fact, all required payments
of annual operating expenses and interest charges have not been made
to Treasury since the project came on line in 1988, with the deferred
payments totalling about $4.1 million at the end of fiscal year 1996.
In addition to the deferred annual expenses and interest payments,
the Washoe Project had $8.9 million of appropriated debt at September
30, 1996.
In January 1997, Western projected that Washoe would have to sell its
power at a rate of at least 5.7 cents per kWh to cover annual
operating expenses (excluding depreciation), interest charges, and
debt repayments. This projection is substantially different from the
Western officials' January 1996 projection that Washoe power would
have to be sold at a rate of at least 11 cents per kWh to cover these
costs. Both projections are substantially higher than the Washoe
average revenue per kWh of energy sales of 1.02 cents in fiscal year
1996. The change in projection by Western is due to the reallocation
of some Washoe costs from power to fish hatcheries protection which,
according to Western officials, does not require recovery through
rates from power customers. We believe that the costs reallocated
are still power-related costs and remain a net cost to the federal
government. As with the Mead-Phoenix Transmission Line, Western
officials said that they were considering combining the Washoe
Project power with the Central Valley Project and establishing a
blended rate that would recover all costs associated with both
projects, noting that they had successfully carried out similar types
of consolidations in the past. However, CVP is itself a problem
project, which would make the risk to the federal government from
Washoe reasonably possible even after a consolidation.
We concur with Western, which stated in its 1995 annual report that
it is unlikely that Washoe will be able to generate sufficient
revenues to repay the federal investment. Moreover, we believe that
as a stand-alone rate-setting system, Washoe will continue to incur
annual operating losses and it is probable that the federal
government will not recover the $13 million\35 of appropriated debt
and deferred payments.
--------------------
\35 This $13 million at risk represents about 0.3 percent of the
federal government's financial involvement of $5,017 million at
Western.
RISK ASSESSMENT FOR THE BONNEVILLE
POWER ADMINISTRATION
======================================================== Appendix VIII
The Bonneville Power Administration (BPA) had over $17 billion of
debt and about $766 million of interest expense as of and for the
year ended September 30, 1996. These high fixed costs limited BPA's
flexibility to lower rates and significantly contributed to BPA's
loss of sales to its preference and industrial customers in recent
years. However, as a result of existing customer contracts, a
memorandum of agreement (MOA) limiting fish and wildlife mitigation
costs, and currently large financial reserves, we believe that the
risk of any significant loss to the federal government from BPA is
remote through fiscal year 2001. After fiscal year 2001, we believe
that expiration of customer contracts, significant risks from market
uncertainties, BPA's high fixed costs, and substantial upward
pressure on other expenses make the risk of loss to the federal
government reasonably possible. This risk will begin to decline
after fiscal year 2012, all else being equal, if BPA pays off its
nonfederal debt as scheduled. One small project that would have
served BPA, Teton Dam, represents a probable financial loss to the
federal government.
THE FEDERAL GOVERNMENT'S
FINANCIAL INVOLVEMENT
------------------------------------------------------ Appendix VIII:1
The federal government has substantial direct and indirect financial
involvement in the activities of BPA. The direct involvement relates
to BPA's appropriated debt, Treasury bonds, and irrigation debt.\1
For all three categories of direct debt, BPA is repaying the federal
government. The federal government's indirect financial involvement
relates to what BPA calls its nonfederal project debt ("nonfederal
debt"),\2 which is due primarily to construction of nuclear projects
of the Washington Public Power Supply System. Table VIII.1 details
the amounts of direct and indirect debt by type.
Table VIII.1
The Federal Government's Financial
Involvement in BPA as of September 30,
1996
(Dollars in billions)
Financial involvement
------------------------------
Description Direct Indirect Total
-------------------------------------- ------ ---------- ==========
Appropriated debt $6.8 $6.8
Treasury bonds 2.5 2.5
Irrigation debt 0.8 0.8
Nonfederal debt $7.1 7.1
======================================================================
Total $10.1 $7.1 $17.2
----------------------------------------------------------------------
--------------------
\1 Aid to Irrigation (which we refer to as irrigation debt) is the
legal obligation to repay costs incurred to construct federal
irrigation projects that are determined by law to be beyond the
irrigators' ability to repay.
\2 BPA used its contracting authority to acquire all or part of the
generating capability of power projects of the Washington Public
Power Supply System, a municipal corporation of the state of
Washington. Under these agreements, BPA contracts to pay all or part
of the annual project budgets, including debt service, whether or not
the projects are completed. BPA does not have the authority to
borrow from nonfederal sources or to construct power generating
facilities.
DIRECT FINANCIAL INVOLVEMENT
---------------------------------------------------- Appendix VIII:1.1
BPA's appropriated debt consists of appropriations primarily used to
construct the generating and transmission projects from which BPA
markets power. The total of $6.85 billion of appropriated debt as of
September 30, 1996, carried a weighted-average interest rate of about
3.5 percent. Retroactively effective to the first day of fiscal year
1997, the Omnibus Consolidated Rescissions and Appropriations Act of
1996 authorizes the restructuring of this debt, reducing the
principal to an estimated $4.29 billion and increasing the associated
interest rate to approximately 7.1 percent. According to BPA's 1996
final rate proposal, the transaction "is intended to permanently
eliminate subsidy criticisms directed at the relatively low interest
rates assigned to historic Federal Columbia River Power System
appropriations."\3 The dates when this debt is due, which extend
through fiscal year 2046 and average about 26 years remaining, are
not changed by the legislation.
According to BPA, the legislated restructuring is such that the
present value of the new (revised) appropriated principal is equal to
the present value of the principal and interest payments scheduled
before the restructuring, plus $100 million. The $100 million is
spread pro rata among all outstanding appropriations and results in
an increase of $100 million in present value terms on related debt
service payments. The resulting new principal amounts are assigned
interest rates based on prevailing Treasury yield curve interest
rates at the time of the transaction. With the exception of the
additional $100 million and the interest on it, we believe that in
substance this transaction does not change the government's future
net financing cost\4 and, even if implemented in fiscal year 1996,
would not have changed the $377 million estimated net financing cost
on BPA appropriated debt for fiscal year 1996.
Beginning in fiscal year 1997, all BPA's appropriations are required
by law to be assigned prevailing Treasury yield curve interest rates.
The Refinancing Act also requires that BPA's Administrator offer to
include in all future and existing contracts for the sale of electric
power, transmission, or related services terms that ensure that
ratepayers pay no more principal and interest on the restructured
appropriations than the act prescribes.
BPA also had about $2.5 billion of medium- and long-term debt held by
Treasury in the form of BPA bonds. BPA's Treasury bond borrowing
stems from authority granted in the Federal Columbia River
Transmission System Act of 1974, as amended, that allows BPA to
borrow up to $3.75 billion directly from Treasury. The $3.75 billion
consists of two separate borrowing authority limits: $1.25 billion
for conservation and renewable energy investments and $2.5 billion
for transmission and other capital investments.\5
In borrowing these funds, BPA sells bonds to Treasury at interest
rates set by Treasury. Interest rates are determined based on
comparable debt with similar terms issued by U.S. government
corporations. The rates are adjusted to reflect the cost of specific
features of BPA's bonds, such as the maturity date and the ability to
call the bonds. The weighted-average interest rate on this debt as
of September 30, 1996, was about 7.5 percent. The 7.5 percent
interest rate results from the combination of BPA refinancing its
Treasury bonds and/or retiring these bonds prior to their maturity.
BPA paid a call premium on this refinancing that was established by
Treasury prior to issuance of the bonds.
In addition to appropriated debt and Treasury bonds, BPA is
responsible for repaying irrigation-related construction costs on
certain Bureau of Reclamation irrigation facilities, as provided by
project-specific authorizing legislation.\6 We refer to this
repayment responsibility as irrigation debt. BPA's irrigation debt
relates to its requirement to pay for irrigation capital costs that
are determined to be beyond the ability of the irrigation water users
to repay. Irrigation debt is generally due up to 60 years after
completion of the construction of the irrigation facilities and is to
be repaid at zero-percent interest. The estimated balance of this
obligation is $841 million as of September 30, 1996. BPA's first
payment of $25 million to the Treasury for irrigation debt is
currently planned to be made in fiscal year 1997; an additional
payment of $10 million is due in fiscal year 2001. The remaining
$806 million is due after fiscal year 2001. Although irrigation debt
is scheduled to be recovered from power revenues, BPA does not view
irrigation debt as a power cost. Instead, BPA discloses this debt in
the notes to the financial statements under "Commitments and
Contingencies." However, if BPA recovers these amounts through its
rates, these costs and revenues will be reflected in its financial
statements. To the extent irrigation debt is recovered through
electricity rates, BPA's power customers are subsidizing irrigators.
The federal government would incur a future loss on direct financial
involvement if BPA failed to make payments on federal debt.
--------------------
\3 BPA is part of the Federal Columbia River Power System (FCRPS),
which also includes the power-related operations of the Corps and the
Bureau. BPA is responsible for marketing power from FCRPS.
\4 However, if BPA repays the principal before it is due, and the
federal government's cost of money has declined, the federal
government will experience a decrease in cash flow and a resulting
increase in net cost.
\5 BPA treats the amount of borrowing authority that it has
"deferred" as part of its financial reserves. Deferred borrowing is
created when BPA uses operating revenues to finance capital
expenditures in lieu of borrowing. This temporary use of
cash-on-hand instead of borrowed funds creates the ability in future
years to borrow money, when fiscally prudent, to liquidate revenue
funded activities.
\6 Project-specific authorizing legislation determines how the costs
of constructing reclamation projects are allocated and how repayment
responsibilities are assigned among the projects' beneficiaries.
Collectively, the Reclamation Project Act that is generally
applicable to all projects and the statutes authorizing individual
projects are referred to as reclamation law. In implementing
reclamation law, the Bureau of Reclamation is guided by its
implementing regulations, administrative decisions of the Secretary
of the Interior, and applicable court cases. The Columbia Basin
Project Act provides for BPA to use its power revenues to repay
Treasury a certain portion of the capital costs allocated to
completed irrigation facilities that are determined by the Secretary
of the Interior to be beyond the ability of the irrigators to repay
(irrigation assistance).
INDIRECT FINANCIAL
INVOLVEMENT
---------------------------------------------------- Appendix VIII:1.2
BPA had nonfederal debt of about $7.1 billion at September 30, 1996.
This debt resulted from BPA's use of its contracting authority to
acquire all or part of the generating capability of power projects of
other entities. Under this arrangement, BPA contracts to pay for all
or part of the annual project budgets, including debt service,
whether the projects are completed or not. Approximately $4.24
billion of this total relates to three nonoperational and canceled
nuclear projects, and an additional
$2.54 billion to one operating nuclear plant. The remaining amount
of about $321 million is for financing of small hydroelectric
projects and conservation measures. The nonfederal debt is not
explicitly guaranteed by the federal government; however, the
financial community views this debt as having an implicit federal
guarantee.
For this indirect involvement, the federal government would incur
future losses for unreimbursed costs related to any actions it took
to prevent default on nonfederal debt service payments or breach of
contract on nonfederal debt by BPA.
RISK OF LOSS FROM BPA IS REMOTE
THROUGH FISCAL YEAR 2001
------------------------------------------------------ Appendix VIII:2
As a result of existing customer contracts, an MOA that put a ceiling
on fish and wildlife mitigation costs and large financial reserves,
we believe that the risk of any significant loss to the federal
government from BPA is remote through fiscal year 2001.
CUSTOMER CONTRACTS
---------------------------------------------------- Appendix VIII:2.1
BPA has succeeded in signing most of its preference customers and
industrial customers to contracts through fiscal year 2001.
According to BPA, its new contracts make more extensive use of "take
or pay" provisions than the old contracts. Such provisions require
the customer annually to buy a specified, minimum amount of
electricity at a set price. The contracts provide a substantial
economic certainty to BPA in terms of the revenues that can be
expected through fiscal year 2001. BPA projects that firm power
sales to these customers will secure $1.14 billion annually through
fiscal year 2001, or approximately 63 percent of each year's total
power revenue. The nature of these contracts and the certainty they
provide strongly mitigate the possibility of financial loss to the
federal government through fiscal year 2001.
FISH AND WILDLIFE COSTS
---------------------------------------------------- Appendix VIII:2.2
BPA bears substantial financial responsibility for measures to
protect fish and wildlife populations and to mitigate damage to
Pacific Northwest fish stocks affected by the construction and
operation of the Federal Columbia River Power System. These costs
include (1) outlays to fund operating and maintenance and capital
costs for fish and wildlife mitigation and protection programs and
(2) revenues BPA has forgone and related costs it has incurred
because of restrictions on the operations of the hydroelectric dams,
which generate the power marketed by BPA. For example, BPA's total
fish and wildlife costs in fiscal year 1996 were $278 million,
including outlays of $176 million to fund fish and wildlife programs
and $102 million in forgone revenues and related costs.
Escalation of these costs in recent years has placed considerable
financial strain on BPA. Figure VIII.1 shows the trend of these
costs, which include both funding outlays for fish and wildlife
programs and revenues forgone because water was used for fish and
wildlife purposes rather than hydropower production.
Figure VIII.1: BPA Fish and
Wildlife Costs, Fiscal Years
1990-1996
(See figure in printed
edition.)
As figure VIII.1 shows, these costs have increased significantly over
time, from $146 million in fiscal year 1990 to $399 million in fiscal
year 1995. Fiscal year 1996 saw a decrease in costs to $278 million,
primarily because a large volume of water was available that year for
both fish and wildlife mitigation and power production.
To address the problem of rising fish and wildlife-related costs, BPA
entered into a MOA with the National Marine Fisheries Service, the
U.S. Army Corps of Engineers, the Bureau of Reclamation, and the
U.S. Fish and Wildlife Service in September 1996. The MOA limited
BPA's fish and wildlife related funding responsibility and helped
make it possible for BPA to offer contracts to its preference
customers for fiscal years 1997 through 2001 at a reduction that
averaged 13 percent, in comparison to rates prevailing in fiscal year
1996.
The MOA's annual total cost includes an agreement to limit actual
funding outlays for fish and wildlife costs to an average of $252
million per year. In addition, BPA agreed to absorb additional costs
in the form of forgone hydropower revenues resulting from water being
used for fish and wildlife-related purposes and the cost of power
purchases made necessary because of the fish protection effort.
Another factor adds to BPA's ability to control its fish and
wildlife-related costs. In each year since the passage of the
Pacific Northwest Electric Power Planning and Conservation Act
(Northwest Power Act) (Pub. Law No. 96-501) in 1980, BPA has funded
fish and wildlife related costs through rates. According to BPA, it
had not recouped the portion of such expenditures that are
attributable to the nonpower portion of the federal system's multiple
purpose projects. Starting with fiscal year 1994, BPA began
recouping these costs by taking credits against its annual Treasury
payment. The credits BPA has taken were $19 million for fiscal year
1994, $56 million for fiscal year 1995, and $31 million for fiscal
year 1996.\7
The MOA describes a "Fish Cost Contingency Fund," which is available
to BPA in certain situations. The fund consists of $325 million in
credits that BPA is authorized to take against amounts otherwise
payable by BPA to the Treasury. The amount in the fund is BPA's
estimate of the portion of fish and wildlife-related expenditures
that BPA made in the years prior to 1994 that were related to the
nonpower purposes of the dams. BPA has not yet found it necessary to
use the contingency fund. According to BPA, the MOA expires in
fiscal year 2001, but the fund does not.
The MOA envisions the possibility that unforeseen events may make
more fish and wildlife mitigation funding necessary, but does not
specify what the funding source will be. It states that the parties
to the MOA, along with the Pacific Northwest Electric Power and
Conservation Planning Council\8 and the region's Indian tribes,
should attempt to reach agreement on how additional funding is to be
provided. If no agreement can be reached, the MOA provides that BPA
is to recommend a funding mechanism to the Office of Management and
Budget and the Council on Environmental Quality.
It is uncertain whether the MOA will be renewed or extended before it
expires in fiscal year 2001. As long as this MOA remains in force,
it provides BPA with protection against fish and wildlife-related
costs exceeding the limit established in the agreement.
--------------------
\7 The amounts for fiscal years 1995 and 1996 are estimates. BPA is
in the process of determining what the final amounts will be.
\8 The Northwest Power Act established the Pacific Northwest Electric
Power and Conservation Planning Council to provide guidance to BPA in
its power planning and fish and wildlife program and other
responsibilities. The Council consists of members appointed by the
primary states served by BPA.
FINANCIAL RESERVES
---------------------------------------------------- Appendix VIII:2.3
BPA currently has substantial financial reserves.\9 The agency had a
$278 million cash and deferred borrowing authority balance at the end
of fiscal year 1996. Because water for the hydropower system has
been plentiful, BPA expects to have a cash and deferred borrowing
authority balance at the end of fiscal year 1997 of about $400
million. In addition, the $325 million Fish Cost Contingency Fund
discussed previously provides a supplementary financial reserve.
These reserves provide BPA with the flexibility to deal with its
operating risks.
However, BPA's reserves could be decreased by factors such as lawsuit
settlements, and BPA's reserve levels have, in the past, varied
considerably over time. An example of this was the decrease from an
$877 million balance at the end of fiscal year 1991 to a $221 million
balance at the end of fiscal year 1993. Also, deferred borrowing
authority may be useful in the short term to provide liquidity, but,
since it results in additional debt, is not a long-term solution to
financial difficulty.
--------------------
\9 BPA financial reserves include cash and deferred Treasury
borrowing authority, and the Fish Cost Contingency Fund constitutes a
supplementary financial reserve, available in specified emergency
situations. Deferred borrowing authority is similar to an unused
line of credit.
RISK OF LOSS IS REASONABLY
POSSIBLE AFTER FISCAL YEAR 2001
------------------------------------------------------ Appendix VIII:3
Because of risks from the expiration of customer contracts, market
uncertainties, BPA's high fixed costs, and upward pressure on other
expenses, the risk of loss to the federal government increases
significantly after fiscal year 2001. Despite a number of factors
that mitigate this risk, we believe it is reasonably possible the
federal government will incur losses relative to BPA after fiscal
year 2001.
CUSTOMER CONTRACTS EXPIRE IN
FISCAL YEAR 2001
---------------------------------------------------- Appendix VIII:3.1
In fiscal year 2001, nearly all of BPA's power contracts with
customers will expire. In that year, BPA projects firm power
revenues from all customers totaling $1.58 billion. In the following
year, should no contract renewals occur, only $286 million in firm
power revenues will be contractually committed--a reduction of 82
percent. BPA has acknowledged this risk and is attempting to
construct new contracts and have them signed before the current
contracts expire. This effort is the result of a December 1996 study
called the Comprehensive Review of the Northwest Energy System
(Comprehensive Review).
The Comprehensive Review was conducted at the direction of the
governors of the four primary states that BPA serves and included an
evaluation of what BPA's role should be in the Pacific Northwest
energy market. One of the study's recommendations was that BPA
devise "subscription contracts." These contracts would be long-term
(5 to 20 years) and would offer benefits to "subscribers"--such as
the ability to purchase from BPA at cost when costs are below market
levels--and would help assure BPA's financial stability. BPA and its
customers are participating in a work group that is developing the
subscription contract concept. BPA's goal is to have the
subscription process implemented and new contracts signed before the
existing contracts expire.
If a significant amount of BPA's power is not contractually obligated
in the future, BPA could be subject to considerable financial risk.
If customers can find cheaper power sources, they might opt to leave
BPA. The agency could find itself in a situation in which it has no
guaranteed, stable market for its power, and could be unable to sell
power on the open market at prices that allow full cost recovery.
SIGNIFICANT RISK FROM MARKET
UNCERTAINTIES
---------------------------------------------------- Appendix VIII:3.2
BPA faces substantial risk from the uncertainties of the wholesale
electricity marketplace. Among these risks are the future production
cost of gas-fired generation plants, the existence of surplus
electric power in the geographic area in which BPA operates, and the
effects of retail open access on BPA and its customers.
NATURAL GAS PRODUCTION
COSTS AND SURPLUS POWER
-------------------------------------------------- Appendix VIII:3.2.1
One of the key market uncertainties that will determine whether
cheaper power will be available in the future is the production cost
of gas-fired generation plants. This generation source has become
increasingly competitive due to low natural gas prices and improving
gas turbine technology. Natural gas prices in the Pacific Northwest
are low due to several factors, including a large supply coming from
Canada. Also, recent technological advances have improved the
efficiency of gas turbines by more than 50 percent. According to
BPA, natural gas-generated power has driven down the price of
wholesale electricity and resulted in customers obtaining some of
their power at rates well below BPA's current rate.
BPA officials stated that natural gas prices will be one of the most
important variables regarding future competitiveness. In its "Future
Focus" planning effort, BPA researched available studies predicting
future gas prices and discovered that there is a wide range of
predictions. BPA selected what it deemed to be the most credible
high-range and low-range predictions for its planning purposes. BPA
concluded that it could remain competitive--even assuming low prices
of gas in the future--if it can lower its costs to 2 cents per
kilowatthour (kWh). BPA's Administrator told us that achieving this
cost level is a primary organizational goal.
The price of natural gas was a primary variable in a 1996 study done
for BPA. The study used three gas price escalation scenarios: base,
low, and high. The base scenario assumed that gas prices would
increase at the rate of inflation. The low-price scenario assumed
that gas prices would be constant in nominal dollars through fiscal
year 2000 and would increase at the rate of inflation thereafter.
The high-price scenario assumed that gas prices would increase at 1.8
percent per year above the rate of inflation. The study generally
found that BPA would not experience stranded costs\10 if gas prices
escalated as assumed in the base and high scenarios. However, under
the low-price scenario, BPA would have stranded costs. In that
scenario, gas prices were assumed to be low, technology was assumed
to make new lower-cost gas plants feasible, and the demand for
electricity was assumed to be low.
According to BPA, surplus power, partially caused by record high
river conditions and high hydropower production in the Pacific
Northwest, is also driving down the price of wholesale power.
Because utilities still are able to pass on fixed costs to captive
retail customers, surplus wholesale power is being sold on a marginal
cost basis. According to BPA, other utilities and power brokers are
offering wholesale power for as low as 1.5 cents per kWh, which is
lower than BPA's price for sales of comparable products at the
current firm rate of 2.14 cents per kWh. It is uncertain whether
surplus power and low cost natural gas generation will continue to
drive down wholesale power prices after fiscal year 2001.
--------------------
\10 As defined by the Federal Energy Regulatory Commission (FERC), a
stranded cost is any legitimate, prudent, and verifiable cost
incurred by a public or transmitting utility that is no longer
economically viable in a competitive wholesale environment.
EFFECTS OF RETAIL OPEN
ACCESS
-------------------------------------------------- Appendix VIII:3.2.2
The possibility of retail open access adds to future uncertainty
about the competitive environment in which BPA and its customers will
operate. BPA sells wholesale power to utilities, which then resell
it on a retail basis. Retail open access--which would provide retail
customers the freedom to choose among suppliers--could result in
BPA's customers being uncertain about the size of their own future
retail sales. This uncertainty would make it unattractive for
customers to sign long-term contracts with BPA until they are
reasonably assured of a stable, predictable retail customer base.
However, even without long-term contracts, BPA is likely to remain a
major supplier. All four states that constitute BPA's primary
service area are considering some form of retail open access, and,
under current law, retail open access will be decided on a
state-by-state basis. However, the Congress is considering various
proposals regarding the approach to retail open access that would be
applied nationally.
BPA'S SUBSTANTIAL
FINANCING COSTS CONTINUE
-------------------------------------------------- Appendix VIII:3.2.3
BPA faces substantial risk beyond fiscal year 2001 because a large
portion of its operating costs are fixed and therefore beyond
management's control. The consequence of this lack of financial
flexibility was demonstrated in fiscal years 1994 and 1995, when
decreasing electricity prices resulted in BPA losing sales to other
providers. Interest expense is BPA's second-largest expense (behind
its operations and maintenance expense) and represents BPA's largest
fixed cost. In fiscal year 1996, BPA paid approximately $766 million
in interest expense on its $17.2 billion in debt. This level of
expense means that BPA used 32 percent of its revenues in fiscal year
1996 to pay the interest on its debt. As shown in figure VIII.2,
BPA's financing costs to revenue ratio is higher than those of
investor-owned utilities (IOUs) and publicly-owned generating
utilities (POGs), whose ratios were 15 and 18 percent (on a
nationwide basis), respectively.
Figure VIII.2: Financing Costs
as a Percentage of Revenues for
BPA, IOUs, and POGs
(See figure in printed
edition.)
Source: Developed by GAO based on data from BPA's 1996 annual report
and national 1995 POG and IOU data from the Energy Information
Administration (EIA).
BPA's relatively high financing costs mean that it has less
flexibility than IOUs and POGs to reduce costs and hence lower rates
to respond to competitive pressures. For example, BPA officials told
us that it lost customers in fiscal years 1994 and 1995 as a result
of its inability to lower rates in response to falling electricity
prices in the Pacific Northwest.
It is important to note that a substantial portion of BPA's debt and
interest expense relates to the construction of nonoperating nuclear
plants. BPA has over $4.2 billion invested in these plants.
Interest expense associated with these plants amounted to over $230
million in fiscal year 1996. This relatively high level of interest
expense can be expected to continue for the foreseeable future,
greatly limiting BPA's ability to react to falling electricity
prices. Also, new borrowing and the potential need to refinance
BPA's Treasury bonds as they mature could expose BPA to the risk of
rising interest rates and even higher financing costs.
BPA is scheduled to have nearly all of its nonfederal debt, including
the debt associated with nonoperating nuclear plants, paid off by
fiscal year 2019. Substantial decreases in scheduled nonfederal debt
servicing begin in fiscal year 2013. Specifically, these debt
service costs are expected to decrease from an average of about $570
million annually from fiscal years 1997 through 2012, to an average
of about $304 million annually from fiscal years 2013 through 2018.
In fiscal year 2019, BPA's scheduled debt service payment declines to
less than $3 million and decreases further in the following years.
If BPA is able to make these payments as scheduled, all else being
equal, its fixed financing costs would be more in line with those of
its competitors. This would result in a reduction of risk to the
federal government over time.
BPA FACES UPWARD PRESSURE
ON OTHER EXPENSES AFTER
FISCAL YEAR 2001
-------------------------------------------------- Appendix VIII:3.2.4
Several factors combine to increase the financial pressure faced by
BPA in the period beyond fiscal 2001. Among them are the expiration
of the fish and wildlife MOA, the inclusion of the full cost of
pension and postretirement health benefits in rates, payments of
irrigation debt, payments to the Colville Tribes, and possible
payments to settle a lawsuit. Taken individually, these factors may
not place substantial pressure on BPA's ability to remain
competitive, but in combination they could have this effect.
It is uncertain whether an agreement similar to the current MOA that
stabilizes fish and wildlife costs will be entered into after the
present one expires. Absent this agreement, BPA is at risk if costs
escalate beyond the MOA limits after fiscal year 2001.
BPA also faces substantial new or additional costs after fiscal year
2001. First, it plans to implement a phased-in approach to
recovering the full cost of pension and postretirement health
benefits in fiscal year 1998, but will defer full recovery until
fiscal year 2002 when $55 million will be due. To completely recover
obligations for fiscal years 1998 through 2001, an additional $35
million will be due in fiscal year 2003. Other costs that will be
incurred over the several decades after fiscal year 2001 include an
estimated $806 million of irrigation debt and BPA's estimated $396
million in payments to the Confederated Tribes of the Colville
Reservation for its share of Grand Coulee Dam revenues. The payments
to the Tribes are to be made annually, and are based on an
agreed-upon range of prices for electricity and the Grand Coulee
Dam's power generation for each year.
The pending lawsuit against BPA by Tenaska Washington Partners, II
L.P. (Tenaska) could result in additional financial pressure on BPA.
In 1994, BPA and Tenaska entered into a power purchase agreement
under which Tenaska was to build and BPA was to purchase the output
of a combustion turbine generating plant. In 1995, BPA gave notice
to Tenaska that "its purpose in acquiring the resource had been
frustrated as a result of the loss of a significant portion of the
load which the resource had been acquired to serve and because the
resource could not operate as intended within the Federal System
because of operational requirements imposed by the 1995 (Endangered
Species Act) Biological Opinion after the power purchase agreement
was executed."
Tenaska and Chase Manhattan Bank (which had arranged the financing
for the canceled project) sued BPA for breach of contract. BPA paid
$115 million to Chase in settlement of Chase's claim. BPA has
entered binding arbitration with Tenaska to settle its claim. The
$115 million payment to Chase is to be offset by any award to
Tenaska. According to the Notes to the Financial Statements in BPA's
1996 annual report, BPA believes that the factual and legal
assertions by Tenaska in support of its $1.125 billion claim are
without merit. However, if the arbitration of this lawsuit results
in a judgment against BPA in an amount substantially in excess of
$115 million, it would increase the risk of financial loss to the
federal government.
MITIGATING FACTORS REDUCE
LONG-TERM PROBABILITY OF
LOSS
---------------------------------------------------- Appendix VIII:3.3
Several factors mitigate the federal government's risk of loss from
BPA. These factors include inherent cost advantages, management
actions that reduce operating costs, and BPA's extensive transmission
system. Because of these factors, we believe the risk of loss to the
federal government after fiscal year 2001 is reduced, but is still
reasonably possible. However, beginning in fiscal year 2013,
nonfederal debt levels are scheduled to decline substantially. If
BPA pays off its nonfederal debt, all else being equal, its fixed
financing costs would be more in line with those of its competitors.
This would reduce the risk to the federal government.
COST RECOVERY STRUCTURE
AND INHERENT ADVANTAGES
CONTRIBUTE TO LOW-COST
POWER
-------------------------------------------------- Appendix VIII:3.3.1
As shown in figure VIII.3, in 1995 BPA's average revenue per kWh was
more than 15 percent lower than IOUs and POGs in the primary North
American Electric Reliability Council (NERC)\11 regions in which BPA
operates. Although BPA's average cost of production is substantially
below that of other utilities, as indicated by its favorable average
revenue per kWh ratio, it is currently facing significant competition
from electricity that is being sold at marginal costs. If the supply
of surplus power subsides and natural gas prices rise, which BPA
believes will happen, BPA's low average production costs should
significantly improve its long-term competitive position.
Figure VIII.3: Average Revenue
per kWh of Wholesale Power
Sold, 1995 (Revenues in cents)
(See figure in printed
edition.)
Source: Developed by GAO based on data from BPA's 1996 annual
reports, preliminary (unaudited) 1995 IOU data from EIA, and POG data
from the American Public Power Association (APPA).
BPA has inherent cost advantages compared to nonfederal utilities.
As discussed in volume 1 of this report, in 1996 BPA did not charge
through to rates nearly $400 million of costs associated with
producing and marketing federal power. These unrecovered power costs
give BPA a significant competitive advantage compared to nonfederal
utilities.
BPA's costs are also minimized by the fact that it markets power
generated mainly by hydroelectric plants built 30 to 60 years ago,
while other utilities are primarily dependent on coal and nuclear
generating plants. Table VIII.2 shows the contrast between BPA and
other utilities in the percentage of power coming from different
generating sources.
Table VIII.2
Percentage of Net Generation for BPA and
Other Utilities, 1996
Coal Nuclear Gas Hydro Other
----------------------------- ------ ------- ------ ------ ------
BPA \0 7.4 0 92.6 0
Other utilities 57.5 24.2 9.7 6.1 2.5
----------------------------------------------------------------------
Source: BPA for BPA data, EIA for other utilities data.
The hydroelectric plants that generate the power marketed by the BPA
and the other PMAs have significant cost advantages over coal and
nuclear generating plants, which are used to generate over 81 percent
of the electricity in the United States. For example, BPA's
hydroelectric plants, which were built decades ago, had relatively
low construction costs. To show the relatively low capital cost of
the hydropower plants, which produced nearly 93 percent of the power
marketed by BPA in fiscal year 1996, we compared BPA's investment in
utility plant per megawatt of capacity for these plants to those of
IOUs and POGs nationwide. As shown in figure VIII.4, BPA has
invested less in plant per megawatt of generating capacity than the
other utilities.\12 Appendix II describes the methodology used for
computing the ratios in figure VIII.4.
Figure VIII.4: Investment in
Utility Plant per Megawatt of
Generating Capacity
(See figure in printed
edition.)
Source: Developed by GAO based on data from BPA's 1996 annual report
and 1995 IOU and POG data from the EIA.
BPA's low investment in utility plant per megawatt of generating
capacity contributes to BPA's relatively low average revenue per kWh,
as shown in figure VIII.3. As discussed earlier, because of BPA's
investment in nonoperational nuclear plants, BPA's overall production
costs are higher than would be the case in the absence of these
investments. This is because BPA has invested over $4.2 billion in
these nonoperating plants, which, while producing no marketable
power, incur substantial interest expense. BPA's investment in
utility plant per megawatt of generating capacity, as shown in figure
VIII.4, would be substantially lower--$630,000 per megawatt--if the
$4.2 billion of nonoperating plant investments were excluded.
Another major reason that hydroelectric plants result in lower
production costs is the cost of fuel. This is particularly important
when comparing hydroelectric plants to coal plants because the cost
of coal is a major operating expense for most other utilities.
Nuclear fuel is also a significant cost, although not nearly as large
a cost as coal. In 1995, POGs' fuel costs represented about 11
percent of operating revenues, while IOUs' fuel costs represented 16
percent of operating revenues. BPA, on the other hand, has the
benefit of marketing power primarily from hydroelectric plants, which
do not have an associated fuel cost.\13
A significant disadvantage of hydroelectric generation is the
unpredictability of water availability. BPA's historical sales
figures demonstrate the dramatic effect that droughts can have on
revenues. For example, 1996 was the best water year since 1974, a
fact which was crucial to BPA's attaining $96 million in net revenues
for the year. Due in part to the additional power generated, BPA's
sales of surplus and nonfirm power increased 296 percent over the
previous year. As previously discussed, another significant
disadvantage of BPA's hydropower generation is the cost associated
with unique fish population improvement measures, which BPA estimated
was $216 million in 1996.
Another key advantage for BPA is that as a federal agency, it
generally does not pay taxes. In contrast, IOUs do pay taxes.
According to the EIA, in 1995 IOUs paid taxes averaging about 14
percent of operating revenues. This average varies significantly
from state to state due to differing state and local tax laws. Taxes
paid by IOUs include federal and state income taxes, real and
personal property taxes, corporate franchise taxes, invested capital
taxes, and municipal license taxes. A specific example of a tax
advantage BPA has relates to its nonfederal debt. The interest
income earned by holders of the bonds issued by the Washington Public
Power Supply System is not subject to federal, personal, and some
state income taxes. This debt carries an interest rate that is lower
than the interest rate applicable to debt of similar risk but without
the tax-free provisions. This provides a measure of benefit to BPA,
which is contracted to pay the Supply System its debt service on the
bonds.
POGs, as publicly owned utilities, typically do not pay income taxes
because they are units of state or local governments. However, many
POGs do make payments in lieu of taxes to local governments. A
study\14 of 670 public distribution utilities showed that the median
net payments and contributions as a percentage of electric operating
revenue were 5.8 percent.
--------------------
\11 We used the 1995 NERC configuration because the latest available
data on average revenue per kWh by NERC region are from 1995. NERC's
configuration changed in 1996. See appendix III for a further
discussion.
\12 Our analysis excluded IOU and POG nuclear plants that are
mothballed and thus provide no capacity while resulting in
significant capital costs. Mothballed nuclear plants can be either
incomplete plants that have had construction terminated or completed
plants that have been shut down either temporarily or permanently.
Under generally accepted accounting principles, these costs are
either written off or, if deemed allowable by the applicable
regulator, are classified as "regulatory assets" and included in
rates through amortization. Inclusion of these "regulatory assets"
would have increased the POG and IOU investment.
\13 Approximately 7 percent of the electricity marketed by BPA in
fiscal year 1996 was produced from nuclear energy.
\14 1994 Payments and Contributions by Public Power Distribution
Systems to State and Local Government, American Public Power
Association, March 1996.
MANAGEMENT ACTIONS
-------------------------------------------------- Appendix VIII:3.3.2
BPA management has taken several actions that are intended to address
the intense wholesale electricity competition in the Pacific
Northwest. These actions have helped make it possible for BPA to
lower rates by about 13 percent for fiscal years 1997 through 2001.
Management's actions have included setting cost reduction targets,
reducing both agency and contractor staff, and refinancing nonfederal
debt and Treasury bonds.
Since 1994, BPA management has set cost reduction targets. To meet
those targets, BPA has analyzed its various spending plans--such as
its fiscal year 1995 budget submission and expenses shown in rate
proposals--and has reduced the expenses that were shown for future
years in those plans. The cumulative total, according to BPA's 1996
annual report, is a cost reduction of $600 million per year. BPA
states that this reduces expenses that would otherwise have been
incurred by $600 million per year during fiscal years 1997 through
2001 and allowed for a 13-percent rate decrease for those years. The
cuts in planned expenses have been widespread to include BPA's
marketing and production, conservation, transmission, and other
activities.
Staff reductions are also part of management's plan. According to
BPA, it has reduced its staff from a total of 3,755 full time
equivalents (FTEs) in March 1994 to a total of 3,160 by the end of
fiscal year 1996. The agency plans a further reduction to 2,755 FTEs
in fiscal year 1999. In addition, BPA told us that it has reduced
its contractor full time equivalents (CFTEs) from 1,911 in fiscal
year 1994 to 1,077 at the end of fiscal year 1996.
In addition, BPA has refinanced its nonfederal debt and Treasury
bonds to keep its interest expense as low as possible. BPA also
plans to use revenue financing (funding capital acquisitions from
current revenues) in some instances to reduce future financing costs.
These plans and actions are consistent with those taken by IOUs in
preparation for competition.
BPA's management is also working with customers to come to an
agreement on phasing out the residential exchange program. This
program allows certain utilities access to BPA's power on an
"exchange" basis. If the utilities' average power costs are higher
than the cost of BPA power, the utilities are authorized to
"exchange" a certain limited amount of their higher cost power with
BPA. BPA reimburses the utilities for the difference between the
higher costs and BPA's cost. The benefiting utilities are to assure
that the exchanged power is sold only to residential and small farm
customers. This program cost BPA $196 million in fiscal year 1996.
The elimination of the program is not, however, within BPA's
discretion. The program is mandated by the Northwest Power Act, and
legislative action would be required to eliminate it.
TRANSMISSION SYSTEM
-------------------------------------------------- Appendix VIII:3.3.3
BPA's extensive transmission system is a significant mitigating
factor in assessing the risk of loss to the federal government. BPA
owns 75 percent of the total bulk power transmission line system in
the region. Ownership of such a large portion of the Pacific
Northwest's transmission capacity should provide BPA with
considerable ability to generate fees for access to this system when
wholesale electricity competition is fully realized. BPA has advised
us that in the event that it is unable to sell its power at a level
that recovers all costs, it might be able to use its massive
transmission system to recover stranded costs. This could involve
allocating stranded generation costs, in whole or in part, to
transmission charges for a period of years.
One uncertainty regarding stranded cost recovery relates to FERC's
requirement that utilities separate transmission and generating
functions. BPA has separated these functions administratively, but
new legislation would be required to establish two separate legal
entities--for instance, two government corporations. The use of
transmission revenues for stranded cost recovery could depend on the
provisions of this legislation.
RISK OF LOSS FROM TETON DAM
PROJECT IS PROBABLE
------------------------------------------------------ Appendix VIII:4
We identified one small project that serves BPA for which we believe
financial loss to the federal government is probable. This project,
Teton Dam, was a multipurpose project on the Teton River in Idaho
built by the Bureau of Reclamation. The dam failed in 1976 when it
was substantially complete, resulting in flooding, loss of life, and
loss of the facilities. Had the project been completed,
power-related construction costs of about $7.3 million and irrigation
costs of about $56.6 million would have been included in BPA's power
rates for eventual repayment to Treasury.
Since the failure of the project in 1976, these costs have been
carried on the books of the Bureau of Reclamation as construction
work-in-progress (CWIP). While CWIP assets normally accrue interest
charges, the Teton project has accrued no interest since 1976. We
estimate that since that time, interest charges of about $5 million,
at the project interest rate of 3.25 percent, would normally have
been paid to Treasury.
The project's power-related construction costs are in the Federal
Columbia River Power System's consolidated financial statements in
the "Other Asset" category and are part of BPA's appropriated debt
balance. However, provisions for recovery of this amount have not
been made. BPA officials told us that since the project was not
formally completed and placed in service, its costs cannot be put
into BPA's rates.
A Bureau of Reclamation official told us that it has no plans for
further construction at the site and that the project should be
written off. According to this official, however, this would require
deauthorization of the project by the Congress. Regardless of
whether the project is deauthorized, we believe these costs are
unlikely to ever be recovered.
RISK ASSESSMENT FOR THE TENNESSEE
VALLEY AUTHORITY
========================================================== Appendix IX
At September 30, 1996, the Tennessee Valley Authority (TVA) had $27.9
billion of debt and $6.3 billion of deferred assets, which leaves TVA
with far more financing and deferred assets than its potential
competitors. The risk that TVA will cause the federal government to
incur losses is remote as long as TVA retains a position in its
service area that is protected from competition--similar to a
traditional regulated utility monopoly.\1
However, if this position changes and TVA is required to compete at a
time when wholesale prices are expected to be falling, its high fixed
and deferred assets compared to neighboring utilities make it
reasonably possible that the federal government would incur future
losses.
--------------------
\1 Regulated monopolies are permitted by the government when
unregulated market forces (for example, economies of scale) would
naturally drive the market from competition to monopoly. In such
situations, the government designates a single seller of a
well-defined product and regulates it to ensure delivery at
acceptable prices.
THE FEDERAL GOVERNMENT'S
FINANCIAL INVOLVEMENT
-------------------------------------------------------- Appendix IX:1
The federal government has financial exposure because of its nearly
$28 billion of direct and indirect financial involvement with TVA.
As shown in table IX.1, the federal government's direct financial
involvement, which consists of appropriated debt\2 and Federal
Financing Bank (FFB) debt, was about $3.8 billion as of September 30,
1996. The federal government's indirect financial involvement, which
consists of TVA's public debt, was $24.1 billion as of September 30,
1996.
Table IX.1
The Federal Government's Financial
Involvement in the Tennessee Valley
Authority as of September 30, 1996
(Dollars in billions)
Financial involvement
----------------------------------
Description Direct Indirect Total
---------------------------------- ---------- ---------- ==========
Appropriated debt $0.6 $0.6
FFB debt 3.2 3.2
Public debt $24.1 24.1
======================================================================
Total $3.8 $24.1 $27.9
----------------------------------------------------------------------
Source: TVA's fiscal year 1996 annual report.
--------------------
\2 In the case of appropriated debt, TVA is required to repay all but
$258.3 million of the appropriations that were used for capital
investments, plus interest. TVA is not required to repay the entire
appropriated debt balance because the federal government wanted to
retain an equity interest in the assets of the corporation. However,
these reimbursable appropriations are not technically considered
lending by the Treasury and are not included in TVA's debt cap. TVA
refers to this debt as "appropriation investment" and considers it to
be equity. Accordingly, TVA considers the annual payments a
reduction of equity capital and the annual return a dividend. For
purposes of this report, we refer to the annual payments as debt
(principal) payments and the annual return as interest expense.
DIRECT FINANCIAL INVOLVEMENT
------------------------------------------------------ Appendix IX:1.1
TVA's appropriated debt consists of appropriations that were
primarily used to construct TVA's hydroelectric and fossil plants,
transmission system, and other general assets of the power program.
Substantially all of this debt was incurred from TVA's inception in
1933 through 1959 when the TVA Act was amended to give TVA the
authority to "self-finance." The 1959 amendments to the TVA Act
require TVA to make annual principal payments (currently $20 million)
to Treasury from net power proceeds plus a market rate of return\3
(interest expense) on the balance of this debt. The annual principal
payments are to continue until the debt is paid down to $258.3
million. TVA estimates that it will pay down its appropriated debt
balance to $258.3 million by the year 2014. TVA is required to
continue to pay annual interest on this balance but is not required
to repay the remaining principal.
TVA's FFB debt stems from authority granted to it in the 1959
amendments to the TVA Act. The amendments authorized TVA to issue
bonds, notes, and other evidence of indebtedness to the public and
the government up to a total of $750 million. Since then, TVA's debt
limit has been increased four times by the Congress: to $1.75
billion in 1966, $5 billion in 1970, $15 billion in 1975, and $30
billion in 1979. In 1994, TVA's Chairman announced that TVA would
stop increasing its debt by October 1997. If this plan is achieved,
TVA would have an internal cap on its debt that is about $2 billion
below its $30 billion statutory debt limit. TVA's outstanding debt
was incurred primarily to finance the construction of its nuclear
program.
For direct involvement, the federal government would incur a future
loss if TVA failed to make payments on its outstanding appropriated
and FFB debt.
--------------------
\3 The annual rate of return (interest expense) on TVA's appropriated
debt is based on the computed average interest rate paid by Treasury
on its total marketable public obligations as of the beginning of
each year. Total marketable obligations include all outstanding
short-term and long-term marketable Treasury securities, including
Treasury bills, notes, bonds, and FFB securities.
INDIRECT FINANCIAL
INVOLVEMENT
------------------------------------------------------ Appendix IX:1.2
Like its FFB debt, TVA's authority to issue public debt stems from
the authority granted under the 1959 amendments to the TVA Act. This
debt has been issued primarily to finance the construction of TVA's
nuclear power program. The federal government's involvement in this
debt is indirect because, although the federal government does not
explicitly guarantee this debt, the major credit rating agencies rate
this debt as if it has an implicit federal guarantee. Therefore,
TVA's public debt is rated based primarily on TVA's links to the
federal government rather than on the criteria that would be applied
to a stand-alone corporation. As a result, the private lending
market has provided TVA with access to billions of dollars of
financing at favorable rates. Debt service on TVA's public debt,
which is payable solely from TVA's net power proceeds, generally has
precedence over the payment of TVA's appropriated debt.
For indirect involvement, the federal government would incur future
losses as a result of unreimbursed costs related to any actions it
took to prevent default on the debt service requirements on TVA's
outstanding public debt.
RISK OF LOSS FROM TVA IS REMOTE
UNDER CURRENT STRUCTURE
-------------------------------------------------------- Appendix IX:2
We believe there are two major factors that protect TVA from
competition and result in TVA operating in a manner similar to a
traditional regulated electric utility monopoly. First, in nearly
all instances, TVA's contracts with its 160 distributors
automatically renew each year and require that at least a 10-year
notice be given before the distributors can switch to another power
company. Second, TVA is exempt from the wheeling provisions of the
Energy Policy Act of 1992. This exemption generally prevents other
utilities from using TVA's transmission system to sell power to
customers inside TVA's service area. TVA also has the added
advantage of being able to set its own rates with a minimum of
oversight. These protections and advantages result in TVA's service
area being substantially without wholesale competition. We believe
the risk of loss to the federal government is remote as long as TVA
remains in this protected position.
LONG-TERM CONTRACTS PROVIDE
STABILITY AND ENSURED CASH
FLOW
------------------------------------------------------ Appendix IX:2.1
TVA's wholesale contracts with its 160 distributors, representing 83
percent of TVA's load, are generally long-term, which assure it a
relatively stable customer base and cash flow. Except for Bristol,
VA, the wholesale power contracts between TVA and its distributors
contain a 20-year term that automatically renews each year (referred
to as the "evergreen" provision) and require that the distributors
give TVA at least a 10- to 15-year notice of cancellation. This 10-
to 15-year notice provision effectively locks the distributors into
purchasing power from TVA since obtaining price quotes for power to
be supplied beginning 10 to 15 years into the future is generally not
feasible. All of the power contracts between TVA and its
distributors are "full requirements" contracts that require the
distributors to purchase all of their electric power from TVA.
TVA'S EXEMPTION FROM
"WHEELING" PROVISIONS
PROTECTS AGAINST OUTSIDE
COMPETITION
------------------------------------------------------ Appendix IX:2.2
TVA is further insulated from competition by a specific exemption
from wheeling provisions of the Energy Policy Act of 1992. Under the
act's provisions, the Federal Energy Regulatory Commission (FERC) can
generally compel a utility to transmit ("wheel") electricity
generated by another utility into its service area for sale to
wholesale customers. The act acknowledges that with certain
exceptions, TVA is legally prohibited from selling power outside its
legislatively mandated service area (referred to as TVA's "fence")
and therefore generally exempts it from having to transmit power from
neighboring utilities to wholesale customers within TVA's service
area. Under the TVA Act and the Energy Policy Act of 1992, TVA is
authorized to allow other utilities to use its transmission lines to
wheel power through its service area to other utilities, but is not
required to allow other utilities to sell power to customers within
TVA's service area.
TVA CAN SET RATES WITH
MINIMUM OVERSIGHT
------------------------------------------------------ Appendix IX:2.3
Another significant advantage for TVA is that unlike other utilities,
the rates TVA charges for its electric power are not subject to
review and approval by state public utility commissions or FERC. TVA
can, and in fact must under the TVA Act, set its rates to recover all
power-related costs. Because the long-term "evergreen" contracts and
the exemption from the wheeling requirements allow TVA to operate
like a traditional regulated monopoly, TVA can set rates at whatever
level it deems necessary to recover all costs and, to a certain
extent, not face the same competitive pressures as other utilities.
Despite this advantage, as is discussed in the next section, TVA has
chosen to defer a substantial amount of costs to future years rather
than beginning to recover these costs from ratepayers.
RISK OF LOSS IS REASONABLY
POSSIBLE ABSENT PROTECTION FROM
COMPETITION
-------------------------------------------------------- Appendix IX:3
Based on discussions with industry experts and TVA officials, it
appears unlikely that TVA will be allowed to maintain its current
regulated monopoly-type structure indefinitely and, at some future
point, will have to compete with other utilities. In a competitive
environment, utilities that have low costs and the flexibility to
adjust their rates to meet those being offered by other utilities are
expected to be the most competitive. We believe TVA's substantial
fixed costs and deferred assets will limit TVA's flexibility to
continue to offer competitive rates and could impact its ability to
recover all costs in a future competitive environment when wholesale
prices are expected to be falling. Therefore, despite a number of
mitigating factors, without protection from competition, we believe
that it is reasonably possible under this scenario that the federal
government would incur future losses as a result of its financial
involvement with TVA.
HIGH FIXED AND DEFERRED
ASSETS WOULD IMPEDE TVA'S
ABILITY TO COMPETE
------------------------------------------------------ Appendix IX:3.1
TVA has chosen to defer costs related to its substantial nuclear
investment to future years rather than currently including them among
the costs being recovered from ratepayers and using the cash
generated to pay down its debt. As a result, TVA had accumulated $28
billion of debt as of September 30, 1996, which resulted in over $2
billion of interest expense in fiscal year 1996.
The recovery of these deferred assets is being put off to the future
and will most likely be scheduled to be recovered from ratepayers at
a time when wholesale power rates are expected to be falling. By
choosing to keep its rates stable over the last 10 years, TVA's
resulting high fixed and deferred assets will leave it vulnerable to
future competition, similar to the Bonneville Power Administration's
(BPA) situation. As mentioned in appendix VIII, BPA's high fixed
costs limited its flexibility to meet competitive challenges when
electricity prices fell sharply in the Pacific Northwest in the last
several years. Like BPA, we believe that TVA's high fixed and
deferred assets would limit its flexibility to react to falling
wholesale prices that are likely to result from competition.
However, unlike TVA, BPA has no deferred nuclear assets.
Following is an assessment of several key ratios that demonstrate why
we believe TVA's high fixed and deferred assets would make it
vulnerable in a competitive environment.
FLEXIBILITY RATIOS
------------------------------------------------------ Appendix IX:3.2
To assess TVA's financial condition relative to its likely
competitors, we compared certain flexibility ratios for TVA and 11
neighboring investor-owned utilities (IOUs).\4 First, we computed the
financing costs to revenue ratio, which indicates the percentage of
operating revenues needed to cover the financing costs of the entity.
The financing costs for TVA consist of the interest expense on its
outstanding debt. Due to the difference in the capital structure
between TVA and the IOUs, we included preferred and common stock
dividends in the financing costs for the IOUs because part of the
IOUs' capital is derived from preferred and common stock and
dividends represent the cost of this equity capital. TVA's capital,
on the other hand, is derived primarily from debt. Next, we computed
the fixed financing costs to revenue ratio, which indicates the
percentage of operating revenues needed to cover the fixed portion of
the financing costs. For this ratio, we excluded the common stock
dividend paid by IOUs because these are not contractual obligations
that have to be paid. For both of these ratios, the lower the
percentage, the greater the financial flexibility of the entity.\5
Table IX.2 shows the results of this comparison.
Table IX.2
Comparison of Financial Ratios for TVA
and Neighboring IOUs That Indicate
Flexibility, Fiscal Year 1996
Fixed
Financing financing
costs to costs to
revenue revenue
Utility (percent) (percent)
-------------------------------------- -------------- --------------
TVA 35.3 35.3
American Electric Power 14.9 7.2
Carolina Power & Light 15.4 6.5
Cinergy 16.3 7.8
Dominion Resources 18.4 8.9
Duke Power 13.4 4.5
Entergy 16.7 11.0
Illinova 13.8 8.8
KU Energy 15.0 5.9
LG&E Energy 3.6 1.5
SCANA 18.6 8.4
Southern 15.7 7.6
IOU Summary
----------------------------------------------------------------------
======================================================================
Average 14.7 7.1
======================================================================
High 18.6 11.0
======================================================================
Low 3.6 1.5
----------------------------------------------------------------------
Source: GAO analysis of 1996 annual reports.
As indicated by table IX.2, TVA's ratio of financing costs to revenue
is more than twice as high as the average financing costs for
neighboring utilities. TVA's ratio of fixed financing costs to
revenue is almost five times higher than the average of its
neighboring IOUs. All of TVA's financing costs are interest expense
and thus are fixed in the short term. On the other hand, IOUs'
common stock dividends are not contractual obligations that have to
be paid. We recognize that short-term stock prices would be
negatively impacted by an IOU's decision not to pay dividends.
However, IOUs have this flexibility and some have elected this option
in the past. These two ratios clearly show that because of high
financing costs, TVA does not have the same level of flexibility as
neighboring IOUs to lower prices to meet price competition.
In addition to TVA's already relatively high financing costs, it also
is exposed to substantial risk of rising interest rates. In fiscal
year 1996, TVA's interest payments alone amounted to just over $2
billion, which represented about 35 percent of its fiscal year 1996
operating revenue. As TVA's approximately $28 billion in debt
matures, the portion that is not repaid will likely need to be
refinanced, thus exposing TVA to the risk of rising interest rates
and even higher financing costs. However, if rates decline, TVA will
experience a decrease in financing costs. For example, as of
September 30, 1996, TVA had approximately $8 billion in long-term
debt that will mature and need to be refinanced over the next 5
years. By the end of this 5-year period, for every 1 percentage
point change in TVA's borrowing cost, its annual interest expense
will increase or decrease by $80 million per year. In addition, as
of September 30, 1996, TVA had about $2 billion of short-term debt
that would also be subject to changes in interest rates.
--------------------
\4 According to industry experts, TVA's competition would most likely
come from nearby utilities because of the cost of wheeling power. We
recognize that utilities that do not border on TVA's service area,
power marketers, and independent power producers (IPPs) also provide
likely competition for TVA. However, we believe that comparing TVA
to its neighboring IOUs provides a reasonable basis for assessing
TVA's ability to compete. See appendix II for a description of these
utilities.
\5 See appendix II for a description and methodology for calculating
these ratios.
DEFERRED ASSET RATIOS
------------------------------------------------------ Appendix IX:3.3
In addition to the two flexibility ratios above, we computed the
ratios shown in table IX.3 to compare the magnitude of TVA's deferral
of costs compared to its most likely competitors. These ratios
measure the relative amount of capital costs that will need to be
recovered in the future via depreciation or amortization. We
computed the accumulated depreciation and amortization to gross
property, plant, and equipment (PP&E) ratio to show how much PP&E has
been depreciated and recovered through rates at September 30, 1996.
A higher ratio indicates that more capital costs have been recovered
through rates. We also computed the deferred assets to gross PP&E
ratio to show how much of total PP&E has not yet begun to be
depreciated and taken into rates. In this case, a lower ratio
indicates fewer deferred assets and a better competitive position.
Table IX.3
Comparison of Financial Ratios for TVA
and Neighboring IOUs That Indicate
Deferred Assets, Fiscal Year 1996
Accumulated
depreciation/ Deferred
amortization assets to
to gross PP&E gross PP&E
Utility (percent) (percent)
---------------------------------------- -------------- ------------
TVA 18.2 19.5
American Electric Power 39.8 1.9
Carolina Power & Light 37.2 1.9
Cinergy 36.4 1.8
Dominion Resources 37.5 1.1
Duke Power 37.3 2.5
Entergy 35.4 1.6
Illinova 34.7 6.2
KU Energy 42.0 2.5
LG&E Energy 37.2 1.5
SCANA 30.1 4.3
Southern 31.9 2.0
IOU Summary
----------------------------------------------------------------------
======================================================================
Average 36.3 2.5
======================================================================
High 42.0 6.2
======================================================================
Low 30.1 1.1
----------------------------------------------------------------------
Note: See appendix II for a description of the methodology used to
calculate these ratios.
Source: GAO analysis of 1996 annual reports.
TVA's ratio of accumulated depreciation and amortization to gross
PP&E was 18 percent as of September 30, 1996, whereas similar ratios
for the IOUs in the comparison group averaged 36 percent. This ratio
shows that only half as much of TVA's capital costs, in percentage
terms, have been taken into its rate base via depreciation and
amortization compared to the average for IOUs.
The second ratio shows that TVA's deferred assets represent 20
percent of its gross PP&E, while the ratio for the 11 IOUs averaged
just 3 percent.\6 TVA's decision to not begin recovering the costs of
the deferred nuclear plants when construction was stopped has
increased the costs that must be recouped in the future. These
ratios show that while TVA has deferred substantial costs, its
potential competitors have written down the assets they deem to be
uneconomical at a much faster rate, which results in these utilities
recovering costs at a much greater pace than TVA and thus having
greater financial flexibility in the future.
The primary component of TVA's deferred assets is $6.3 billion in
capital costs for its nonproducing nuclear assets (Watts Bar 2 and
Bellefonte 1 and 2 nuclear units\7 ). TVA has deferred these costs
based on its unique interpretation and application of accounting
principles. Despite the fact that there are no other deferred
nuclear plants in the United States, TVA is treating Watts Bar 2 and
the Bellefonte units similar to construction work-in-progress (CWIP).
As such, the recovery of the costs of these assets will not begin
until the units are either completed and placed in service or
canceled.
In December 1994, TVA determined it would not, by itself, complete
Bellefonte units 1 and 2 or Watts Bar 2 as nuclear units. However,
TVA is still studying the potential for converting Bellefonte to a
combined cycle plant and/or joint-venturing with a partner for
completion of the plant. This study is scheduled to be completed by
the fall of 1997. TVA also concluded, as part of its Integrated
Resource Plan, that Watts Bar 2 should remain in deferred status
until completion of the Bellefonte study.
We believe that the $6.3 billion of costs are appropriately
capitalized as an asset in accordance with Statement of Financial
Accounting Standards (SFAS) No. 71, Accounting for the Effects of
Certain Types of Regulation. However, as we reported in 1995 (See
our report Tennessee Valley Authority: Financial Problems Raise
Questions About Long-term Viability (GAO/AIMD/RCED-95-134, August 17,
1995)), we believe that it is unlikely that these projects, which
have not had any construction work done for 9 years, will ever be
completed as nuclear units. SFAS No. 90, Regulated
Enterprises--Accounting for Abandonments and Disallowances of Plant
Costs requires that "When it becomes probable that an operating asset
or an asset under construction will be abandoned, the cost of that
asset shall be removed from construction work-in-process." In our
judgment, SFAS No. 90 requires that TVA's $6.3 billion of costs be
reclassified from CWIP to "regulatory assets" and that amortization
begin immediately. We believe that TVA's continued exclusion of
these costs from charges to ratepayers reduces the likelihood of
recovery from ratepayers and puts the federal government at increased
risk of absorbing these costs in the future.
TVA charges the costs of its PP&E and canceled plants to ratepayers
through depreciation and amortization expenses. TVA is required by
law to set rates so that power revenues cover all operating expenses,
including depreciation and amortization. While the nonproducing
nuclear assets are not presently being depreciated or amortized, the
annual interest expense from the debt associated with these assets is
included in TVA's current charges to ratepayers. By not recovering
the costs of its deferred nuclear units from ratepayers and using the
cash to pay off debt in prior years, TVA has developed high fixed
costs and deferred assets which will place upward pressure on TVA's
rates at a time when power rates are expected to be falling.
--------------------
\6 The IOUs deferred assets primarily represents construction
work-in-progress.
\7 TVA suspended construction activities on Watts Bar 2 in 1988, and
the unit is currently in lay-up status. In 1988 and 1985, TVA
deferred construction activities at Bellefonte 1 and 2, respectively.
INVESTMENT IN PP&E PER
MEGAWATT OF GENERATING
CAPACITY
------------------------------------------------------ Appendix IX:3.4
Finally, to analyze TVA's competitiveness with its 11 neighboring
utilities, we compared the investment in PP&E per megawatt of
generating capacity--which depicts the relative cost of building
generating plants--with the average system retail rates. High
investment in PP&E generally means higher rates. As shown in figure
IX.1, TVA has more invested in power plants in relation to their
generating capacity than most other utilities in our comparison
group, yet its rates are generally lower than the group.\8
Figure IX.1: Comparison of
Investment in PP&E and Retail
Rates Among TVA and Neighboring
IOUs
(See figure in printed
edition.)
Note: Data for TVA are from fiscal year 1996. TVA's average system
retail rate represents the average system retail rates for its
distributors.
Source: GAO analysis of financial data in 1995 annual reports and
Financial Statistics of Major U.S. Investor-Owned Utilities 1995 and
Inventory of Power Plants in the United States, Energy Information
Administration (EIA), January 1996.
TVA's relatively high investment in utility plant results from its
high investment in nuclear plants. As shown in figure IX.1, of the
11 utilities in our comparison group, only Illinova has invested more
in PP&E per megawatt of generating capacity than TVA. Figure IX.1
also shows that Illinova's average rate is higher than the average
system rates for TVA's distributors. In addition, KU Energy, which
had the lowest investment in PP&E per megawatt of generating
capacity, also had the lowest average rates. TVA's relationship
between its investment in PP&E per megawatt of generating capacity
and rates does not follow this pattern. TVA has invested more in
assets per megawatt of generating capacity than all but one IOU in
our comparison group, but has lower rates than all but three of the
IOUs. TVA's low rates have been significantly impacted by its
decision to defer substantial costs and cost advantages--discussed
later in this appendix--from being a government corporation.
--------------------
\8 Our analysis excluded nuclear plants that are mothballed and thus
provide no capacity while resulting in significant capital costs.
Mothballed nuclear plants can be either incomplete or completed
plants that have had construction terminated or have been shut down
either temporarily or permanently. Under generally accepted
accounting principles, these costs are either written off or, if
deemed allowable by the applicable regulator, are classified as
"regulatory assets" and included in rates through amortization.
Inclusion of these "regulatory assets" would have increased the IOUs'
investment.
TVA FACES SOME COMPETITIVE
PRESSURE TODAY
------------------------------------------------------ Appendix IX:3.5
While TVA's wholesale rates look relatively competitive in the
Southeast, we believe TVA's competitive position will be weakened
when it begins to recover the $6.3 billion of deferred assets. TVA's
vulnerability to wholesale competition, without protection, was
recently demonstrated when one of its customers, Bristol Virginia
Utilities Board, announced that it will leave the TVA system for
Cinergy, Inc. Cinergy offered Bristol firm wholesale power at 2.59
cents per kilowatthour (kWh) for 7 years--40 percent lower than TVA's
comparable wholesale rate of 4.3 cents per kWh. According to its
General Manager, Bristol will save $70 million over 7 years, and the
typical residential customer will save $11 per month. Bristol, which
is on the border of TVA's service area, was able to purchase this
power because it had given TVA written notice of its intent to cancel
its power contract and had received a unique exemption in the Energy
Policy Act of 1992, which allows other utilities to transmit (wheel)
electricity to Bristol over TVA's power lines. As a result of
Bristol's exemption, TVA is required to wheel Cinergy's power to
Bristol. While we recognize that Cinergy may have offered this power
to Bristol at marginal rates, this is the type of competitive
situation that TVA might face regularly if it lost its current
protections from competition.
The concerns of TVA industrial customers--which represent
approximately 15 percent of its load--about future price increases
will put pressure on TVA not to raise rates and thus to continue to
defer costs and maintain high debt levels. Unlike residential
customers, the larger industrial entities are willing and able to
leave a utility's service area to find alternative, cheaper sources
of power. Officials from the Tennessee Valley Industrial Committee
and Associated Valley Industries, which represent industries that
purchase electric power directly from TVA or through TVA's rural or
public power distributors, told us that they believe there is room
for TVA to lower its firm power rates. They stated that any increase
in industrial rates would be unwelcome because they believe TVA's
current rates are too high when compared to the firm industrial rates
of other utilities. The officials said they would continue to
advocate cost control and more favorable firm power rates.
OTHER FACTORS COULD
NEGATIVELY AFFECT TVA
------------------------------------------------------ Appendix IX:3.6
In addition to TVA's high fixed and deferred assets, we believe the
concentration of TVA's sales to its five largest distributors and the
number of TVA's customers that are already connected to the
transmission line of other utilities also contribute to TVA being
vulnerable to future competition.
TVA's customer profile may increase competitive pressures. TVA sells
electric power at wholesale rates to 160 municipal and cooperative
power distributors, the majority of which are relatively small. In
fiscal year 1996, over 63 percent of the distributors had a peak
demand of less than 110 megawatts. However, five municipal
distributors account for over 34 percent of TVA's total sales to
distributors (Chattanooga, Knoxville, Memphis, and Nashville,
Tennessee, and Huntsville, Alabama). TVA's largest distributor, the
City of Memphis, had a peak demand of about 2,943 megawatts in fiscal
year 1996--representing approximately 11 percent of TVA's total sales
to distributors. Because Memphis is at the edge of TVA's service
area, it may be particularly vulnerable to competitive advances of
other utilities.
Officials from these large distributors expressed concern that TVA's
power contracts offer distributors no flexibility to purchase power
from outside sources. The officials discussed a number of possible
options that TVA should consider, including shortening the length of
its power contracts, giving distributors the freedom to fill some of
their requirements from outside sources, or tying its wholesale rates
to a market index. The large distributors hope to use their leverage
in order to compel TVA to renegotiate their power contracts. In a
competitive environment, TVA would likely have to lower the rates of
these distributors or run the risk of losing them as customers, which
could be financially crippling to TVA.
Another competitive pressure arises because although TVA is exempt
from the wheeling provisions of the Energy Policy Act of 1992, 12 of
TVA's 160 distributors are already interconnected with other
utilities. Therefore, even if other utilities are prevented from
using TVA's lines, these distributors could get power from other
sources after their contracts with TVA expire. These distributors
are scattered around the periphery of TVA's service territory. Some
of these distributors are connected to both TVA and other utilities,
whereas others are not connected to TVA's transmission network at
all. According to one TVA study,\9 26 percent of the load for
distributors on the periphery of TVA's system is served by
transmission lines owned by other utilities. This load accounts for
approximately 2 percent of TVA's total load. As competition
intensifies in the region, TVA could lose distributors to other
suppliers using existing and future transmission connections.
--------------------
\9 The Ties That Bind: TVA in a Competitive Electric Market, Palmer
Bellevue, a division of Coopers & Lybrand L.L.P., April 1995.
MITIGATING FACTORS REDUCE
RISK OF LOSS
------------------------------------------------------ Appendix IX:3.7
TVA has a number of factors that mitigate its high fixed and deferred
assets. These factors include inherent cost advantages, management
actions to cut operating expenses, and an extensive transmission
system. Because of these factors, we believe the risk of loss to the
federal government is reduced but is still reasonably possible.
INHERENT COST ADVANTAGES
---------------------------------------------------- Appendix IX:3.7.1
According to bond rating agencies, TVA's creditworthiness is based on
its links to the federal government rather than on the criteria
applied to a stand-alone corporation. As a result, the private
lending market has provided TVA with access to billions of dollars of
financing at favorable rates. In accordance with section 15d of the
TVA Act, TVA's debt issuances explicitly state on the bond prospectus
that the bonds are neither legal obligations of, nor guaranteed by,
the U.S. government. Nevertheless, TVA's bonds are rated by the
major bond rating agencies as if they have an implicit federal
guarantee. One of the major bond rating services believes, and we
concur, that without the links to the federal government, TVA would
have a lower bond rating and higher cost of funds.
TVA also enjoys many advantages as the direct result of being a
federal corporation. As a federal government corporation, TVA is
exempt from federal and state income taxes and does not pay various
local taxes. Therefore, TVA, as a nonprofit entity, does not have to
generate the net income that would be needed by an IOU to provide an
expected rate of return. However, the TVA Act requires TVA to make
payments in lieu of taxes to state and local governments where power
operations are conducted. The base amount TVA is required to pay is
5 percent of gross revenues from the sale of power to other than
federal agencies during the preceding year--these amounted to about
$256 million in fiscal year 1996. In addition, according to TVA, its
distributors are required to pay various state and local taxes which
amounted to about $125 million, or about 2 percent of the total
fiscal year 1995 operating revenues of TVA and the distributors. In
comparison, according to the EIA, IOUs pay about 14 percent of
operating revenues for taxes. In addition, interest income for TVA's
bondholders is generally exempt from state income taxes, which
further lowers TVA's costs of funds.
TVA has relatively more hydroelectric power than neighboring
utilities. Eleven percent of its power comes from hydroelectric dams
built between 1912 (pre-TVA) and 1972--20 to 85 years ago, whereas,
on the average, only about 6 percent of the power from other
utilities comes from hydroelectric dams. These established
hydroelectric projects are relatively inexpensive and have no
associated fuel costs. TVA continues to upgrade and improve its
hydroelectric plants. TVA has 113 hydro units at 29 conventional
dams and the Raccoon Mountain Pumped-Storage facility on the
Tennessee River and its tributaries that produce electricity. TVA is
refurbishing and upgrading 88 hydro units at 24 hydroelectric dams as
part of its Hydro Modernization Program. In addition, TVA also
dispatches power from four hydroelectric dams that are owned by a
subsidiary of the Aluminum Company of America. Table IX.4 shows the
contrast between TVA and other utilities in the percentage of power
from different generating sources.
Table IX.4
Percentage of Power Generation From
Different Sources for TVA and Other
Utilities, 1996
Utility Coal Nuclear Gas Hydro Other
----------------------------- ------ ------- ------ ------ ------
TVA 65.0 24.0 0 11.0 0
Other utilities 57.5 24.2 9.7 6.1 2.5
----------------------------------------------------------------------
Source: TVA and EIA.
TVA also has a competitive advantage because it purchases low cost
hydroelectric power from Southeastern. According to TVA, it
satisfies about 2 percent of its annual power needs from the power
marketed by Southeastern, which represents about 80 percent of the
power marketed by Southeastern from the dams on the Cumberland river.
In fiscal year 1996, TVA purchased this power at 0.8 cents per
kWh.\10
--------------------
\10 See volume I for a discussion of Southeastern's cost advantages
that allow it to market low cost power.
MANAGEMENT ACTIONS AND
PLANS TO REDUCE COSTS AND
INCREASE REVENUES
---------------------------------------------------- Appendix IX:3.7.2
Recently, TVA has taken a number of steps to reduce its operating and
capital expenses and become more competitive. For example, it
canceled a number of its nuclear construction projects in the early
1980s and reduced annual operating costs by nearly $800 million,
primarily by cutting its workforce in half (from 34,000 in 1988 to
16,000 in 1996) and refinancing its debt at lower interest rates.
Another important step for TVA is the completion of its Watts Bar 1
and restarting of its Browns Ferry 3 nuclear power units, which were
major reasons for TVA's increased debt in recent years. In addition,
according to TVA, it has internally capped its debt limit at about
$28 billion and plans to finance its future capital expenditures from
operations.
On July 22, 1997, TVA released a 10-year business plan that
identifies actions it plans to take to position its power operations
to meet the challenges from the coming restructured marketplace.
This plan calls for TVA to (1) increase power rates enough to
increase annual revenues by about 5.5 percent ($325 million), (2)
take various actions to reduce its total cost of power by about 16
percent by fiscal year 2007, (3) limit annual capital expenditures to
$595 million, and (4) reduce debt by about 50 percent from $27.9
billion as of September 30, 1996, to $13.8 billion by fiscal year
2007. To the extent TVA is able to use the cash generated from
increasing rates, reducing expenses, and capping future capital
expenditures to pay down debt, the risk of loss to the federal
government is reduced. In addition to these actions, the plan calls
for TVA to change the length of the wholesale power contracts with
its distributors from a rolling 10-year term to a rolling 5-year term
beginning 5 years after the amendment. However, reducing the length
of the wholesale contracts with its distributors could increase the
risk of loss to the federal government.
EXTENSIVE TRANSMISSION
SYSTEM
---------------------------------------------------- Appendix IX:3.7.3
A major advantage to TVA in a competitive environment will be that
TVA owns and operates an extensive transmission system extending into
seven states and consisting of 17,000 miles of high voltage lines
interconnecting with 16 neighboring utilities at 57 interconnecting
points. Even if TVA is forced to allow other utilities to use its
power lines to sell power to its customers, TVA will have the right
to charge the other utilities a fee for using its transmission lines.
During 1996, TVA spent $228 million to expand and improve the
reliability of the transmission system, and it projects spending an
average of approximately $183 million annually for fiscal years 1997
through 2001 to further improve and upgrade its transmission
facilities.
TVA believes it has legal authority to recover stranded costs from
customers that may choose to leave the system and will be able to use
charges for use of its transmission lines to do so. Various other
mechanisms could also be used for the recovery of stranded costs,
including fees charged to customers that have or may decide to
discontinue purchasing TVA power. However, TVA recognizes that there
are legal, political, and commercial uncertainties regarding the
possibility of recovering stranded costs.
(See figure in printed edition.)Appendix X
COMMENTS FROM THE RURAL UTILITIES
SERVICE
========================================================== Appendix IX
(See figure in printed edition.)
(See figure in printed edition.)
The following are GAO's comments on the Department of Agriculture's
letter dated July 8, 1997.
GAO COMMENTS
1. Our April 1997 report presented information on the financial
condition of the RUS loan portfolio as of September 30, 1996, and
included selected financial statistics and ratios reported by the RUS
borrowers. We also noted in that report that "RUS' electricity
portfolio faces the possibility of additional financial stress due to
increasing competition among the providers of electricity." The
current report addresses this issue and assesses the likelihood of
future losses to the federal government from its direct and indirect
involvement in RUS. For example, we determined that $10.5 billion of
the $32.3 billion, or 33 percent, of the total electricity portfolio
represented loans to borrowers that are in bankruptcy or otherwise
financially stressed. It is probable that the federal government
will continue to incur substantial losses from loan write-offs
relating to RUS borrowers that are currently bankrupt or financially
stressed.
It is also probable that future losses will arise from other RUS
borrowers with high production costs based on our analysis that shows
that 27 of the 33 viable G&T borrowers had higher production costs
than the IOUs in their regions. We believe that current production
costs will be a key factor in the ability of RUS G&Ts to compete in a
deregulated environment. In fact, RUS officials told us that several
borrowers currently considered viable by RUS have already asked RUS
to renegotiate or write off their debt because they do not expect to
be competitive due to high production costs.
2. We agree that the publicly rated G&Ts are better positioned to
remain viable power supply borrowers. However, only 7 of the 55 RUS
power supply borrowers are publicly rated by bond agencies. In
addition, in May 1995, Moody's Investors Service issued an opinion on
the viability of RUS borrowers in their report entitled, Moody's
Outlines Risk Profile for Electric Cooperatives. It states:
"Historically, G&Ts have had a number of structural
disadvantages in competing with IOUs, including generally higher
rates, transmission constraints, lower equity ratios, and
capacity planning problems. Moreover, they also face the need
to find new sources of funding to compensate for the reduced
availability of guaranteed loans from RUS. We expect that the
confluence of factors will result in the deterioration of the
overall credit quality of the cooperative industry over the next
5 to 10 years."
3. Discussed in the "Agency Comments and Our Evalution" section of
the letter in volume 1.
(See figure in printed edition.)Appendix XI
COMMENTS FROM SOUTHEASTERN,
SOUTHWESTERN, AND WESTERN
========================================================== Appendix IX
(See figure in printed edition.)
(See figure in printed edition.)
(See figure in printed edition.)
(See figure in printed edition.)
(See figure in printed edition.)
(See figure in printed edition.)
The following are GAO's comments on the three PMAs' letter dated July
1, 1997.
GAO COMMENTS
1. Discussed in the "Agency Comments and Our Evaluation" section in
the letter in volume 1.
2. We agree. We have added to volume 1 of our report a discussion
of the 1983 change in guidance on setting interest rates for
PMA-appropriated debt.
3. We have appropriately included all salient points relative to the
three PMAs' net cost and risk to the federal government in both
volume 1 and appendix VII of volume 2. Additionally, we disagree
with the three PMAs' characterization of certain costs as
"disadvantages." For example, we do not agree that including future
replacement costs in Southwestern's power rates have increased its
rates by 10 to 15 percent. The revenues generated by including these
costs in current rates have actually been applied to current year
appropriations or other appropriated debt. As a result, Southwestern
has been able to repay most of its recent higher interest rate debt.
Thus, its weighted average interest rate was 2.9 percent,
considerably lower than Southeastern's (4.4 percent) and Western's
(6.0 percent). Southwestern's repayment of higher rate debt has
enabled it to minimize interest expense and electricity rates for its
customers. Rather than viewing this as a "cost disadvantage" to
Southwestern or its customers, we believe Southwestern has managed
its appropriated debt using sound business principles and has
minimized the interest expense that must be recovered through rates.
Regarding the requirement to repay irrigation debt, the three PMAs
overstate the impact of this requirement on Western. Our review of
Western's fiscal year 1996 financial statements shows that, as of
September 30, 1996, the cumulative total amount of irrigation
investment repaid by Western was just over $33 million. A cumulative
total repayment of that amount does not represent a significant cost
disadvantage for an entity that has had gross annual operating
revenues averaging more than $775 million over the 5-year period from
1992 through 1996. We agree that to the extent that power revenues
are actually used to repay irrigation investment it is a disadvantage
to power customers; however, we do not agree that the impact has been
significant enough to be highlighted in volume 1 of the report.
The three PMAs also overstate the likely impact of Western's
potential repayment of future irrigation investments. The billions
of dollars that the three PMAs refer to are not costs that have been
incurred, and it is questionable whether they will ever be incurred.
To the extent that these planned future costs are included in
Western's current rates, any resulting revenue would actually be
applied to other appropriated debt. Until these future irrigation
costs are incurred and repaid, or funds are set aside for their
future repayment, they do not represent a disadvantage to Western or
its customers.
Regarding payments made in lieu of taxes, we acknowledge in appendix
VII that the Boulder Canyon Project, marketed by Western, makes
annual payments in lieu of taxes to the states of Arizona and Nevada.
In 1995, the payments totaled about $600,000, or 1.2 percent of the
Boulder Canyon Project's operating revenue. In contrast, according
to the Energy Information Administration, IOUs paid taxes averaging
about 14 percent of operating revenues in 1995. Moreover, despite
raising the issue of payments in lieu of taxes, the three PMAs have
been unable to substantiate that they or the operating agencies have
made any payments in lieu of taxes other than those to the states of
Arizona and Nevada.
4. We concur with the three PMAs' comment that the three PMAs'
costs, and resultant power rates, are generally lower than their
competitors. In our report, we used average revenue per kilowatthour
(kWh) to demonstrate this favorable comparison.
5. We disagree. It is appropriate to include the irrigation debt in
our discussion of the federal government's financial involvement in
electricity-related activities because it is to be recovered
primarily by power revenues.
6. We do not agree that the investments in Russell, Truman, and
Washoe are "new investments." Construction on Russell began in 1976,
the four operating units came on line in 1986, and the four
nonoperational units were completed in 1992. The nonoperational
units at Truman were specifically deferred from inclusion in rates as
part of FERC's approval of Southwestern's 1989 power rates. Power
sales at Washoe began in 1988. Thus, Russell, Truman, and Washoe
have a history of operating and financial problems. We see no
evidence provided by the three PMAs that this troubled past will not
continue. We concur that Mead-Phoenix, which began operation in
April 1996, can be considered a "new investment." However, the
results we report for Mead-Phoenix's first 9 months of operation,
coupled with the lack of customers for Western's share of capacity,
demonstrate that this investment meets the criteria for a probable
future loss to the federal government.
7. In volume 1, we conclude that the three PMAs are competitively
sound overall, except for a few projects or rate-setting systems
that, taken as a whole, make risk of some loss to the federal
government probable. We then discuss these projects in detail in
appendix VII. Because we assess the three PMAs as competitively
sound overall, a discussion of mitigating factors in volume 1 is not
needed. The mitigating factors we identified for each of the three
PMAs are discussed in appendix VII.
8. We agree that the risk of loss at Russell is conditional. As
stated in appendix VII, if the nonoperational pumping units do not
operate commercially, it is probable that the federal government will
lose its entire $518 million investment. In addition, we state that,
if full deployment of the pumping units continues to be delayed, the
risk of loss to the federal government is reasonably possible. Also,
if the nonoperational pumping units are allowed to operate
commercially and placed into rates in the near future, the
Georgia-Alabama-South Carolina system, of which Russell is a part,
should be able to remain competitive. Under this scenario, the risk
of loss to the federal government is remote. We have added language
to appendix VII to clarify the conditional assessment of risk at
Russell.
9. The statement that the "Army Corps of Engineers expect this
project's pumpback units to operate" is contrary to what the Corps of
Engineers told us. In addition, the fact that the costs associated
with the nonoperational pumping units have been deferred from
Southwestern's rates since 1989 suggests that the outcome is very
uncertain. Moreover, we disagree that Southwestern would be able to
absorb the full cost allocated to power and still remain competitive
even if the pumping units do not operate. Even if Southwestern has
the financial capability to absorb these costs, this assertion by
Southwestern overlooks the policy guidance contained in DOE Order
RA6120.2, which indicates that if the nonoperational units are not
put into commercial service, the power customers will not be required
to repay the investment. Therefore, if the pumping units remain
nonoperational, it is irrelevant whether Southwestern could afford to
absorb the costs. However, we have added language to appendix VII to
clarify that if the nonoperational units at Truman do operate
commercially and are placed into rates, the risk of loss to the
federal government is remote.
10. We correctly stated in our draft report that the Central Valley
Project (CVP) incurred a net loss of $24 million in fiscal year 1996,
as evidenced by the "Net Deficit" of over $24 million shown for CVP
in Western's audited financial statements for that year. Also, we do
not agree with the three PMAs' inference that depreciation should not
be considered an expense. Although a noncash expense, depreciation
allocates the costs of fixed assets over their useful lives.
However, we have added a statement to appendix VII that CVP was able
to meet its cash flow requirements in fiscal year 1996.
We believe that the three PMAs have misread our discussion of the
potential impact of the Central Valley Project Improvement Act
(CVPIA) on CVP. We stated that CVPIA emphasizes the need to
safeguard fish and wildlife and, as a result, less water may be
available for irrigation, power generation, and other purposes. We
go on to state that to the extent that the act's implementation
reduces power revenues, the uncertainty over the repayment of the
federal government's investment in CVP's hydropower facilities
increases. We did not attempt to predict the act's ultimate impact
but did describe how the act increases the uncertainty surrounding
CVP. Assessing and describing such uncertainty is appropriate when
assessing the federal government's risk of future financial losses.
Considering and discussing prices, long-term and short-term, is
appropriate in a competitive environment. In our opinion, the
actions taken by Western to respond to competition (that is,
decreasing CVP's rates by 26 percent in 1996 and planning to further
reduce rates by exercising escape clauses in purchase power
contracts), which our draft report discusses, support this belief.
Regarding the three PMAs' comment that they could not fully
understand why we describe the situation at CVP as "uncertain" while
describing BPA's near-term risk as "remote," the primary difference
is that BPA has contracts in place that mitigate the federal
government's risk of future financial losses at BPA for the next few
years. Thus, the risk at BPA is remote in the near term.
We have added language to appendix VII regarding the potential
reduction in Trinity River water flows to CVP and the impact on the
federal government's risk of future financial losses at CVP.
11. The scope of our work did not include reporting on congressional
intent regarding the ultimate repayment of the suballocated
irrigation investment.
12. We agree that this investment is early in its repayment period
and that financial results may change. However, since project
expenses have totalled nearly $7.3 million to date, compared to only
$71,319 in revenues, it will be very difficult to achieve the
dramatic financial improvement necessary to make the project viable.
Because of the lack of demand for power from the line, it appears
unlikely that Western will be able to successfully market its entire
transmission capacity and recover all relevant costs. As we report,
Western officials are discussing blending the line's rate with the
rate for the older Intertie system, which they believe will increase
project revenue and provide greater certainty of Mead-Phoenix
repayment. However, requiring the Intertie to absorb the
Mead-Phoenix losses would negatively impact the financial condition
of the Intertie. We believe our characterization of the situation as
a probable loss if the consolidation under consideration cannot be
successfully implemented is correct. In addition, we have added
language to appendix VII clarifying our opinion that even if the
consolidation can be completed, there is no indication that the
demand for power from the line will increase or that Western will be
able to successfully market its transmission capacity. Therefore,
under this scenario there is a reasonably possible risk of future
loss to the federal government.
13. We agree with the three PMAs' statement that proposals by
Western to blend Washoe's power with CVP after 2004 could change the
risk related to Washoe. However, blending Washoe's high-cost power
in with the CVP system would compound the financial difficulties
facing CVP that we discuss in appendix VII. We believe that we are
correct in concluding that as a stand-alone rate-setting system,
Washoe presents a probable risk of loss of the entire federal
investment, including deferred payments, of $13 million. In
addition, we have added language to appendix VII clarifying that even
if the consolidation can be completed, the risk to the federal
government of future financial losses from Washoe is reasonably
possible, since CVP is itself facing financial difficulties.
14. The unique circumstances of the six entities make it unfeasible
to portray this complex information in tabular form. The three PMAs'
proposed table gives a distorted picture of the magnitude of the risk
by entity. Additionally, the three PMAs may have misunderstood our
assessments of risk. We did not conclude that each problematic
system represents a probable loss to the federal government. Rather,
we concluded that for the three PMAs as a whole, the risk to the
federal government of some future financial loss is probable. We
added language to appendix VII clarifying the overall risk to the
federal government for the three PMAs and for each of the specific
problematic projects.
15. Although determining the extent to which congressional action
would be required for the PMAs to recover these costs was beyond the
scope of our review, we do not believe that specific legislation
would be necessary in order for all of the categories of unrecovered
costs to be recovered. For example, the PMAs could recover the full
costs associated with Civil Service Retirement System (CSRS) pensions
and postretirement health benefits by including these costs in rates
and depositing amounts recovered, like many other PMA ratepayer
collections, into the General Fund of the Treasury. This would allow
the revenue to be available to the Congress to appropriate into the
Fund to cover the full cost of CSRS pensions and postretirement
health benefits.
(See figure in printed edition.)Appendix XII
COMMENTS FROM THE BONNEVILLE POWER
ADMINISTRATION
========================================================== Appendix IX
(See figure in printed edition.)
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Now on pp. 17, 18, 28, and 29.
The following are GAO's comments on the Bonneville Power
Administration's letter dated June 27, 1997.
GAO COMMENTS
1. Discussed in the "Agency Comments and Our Evaluation" section in
the letter in volume 1.
2. The scope of this assignment did not include examining the public
benefits that BPA and the other agencies that were the subject of our
review provide to their respective regions. However, our report
states that BPA has substantial financial responsibilities and costs
with regard to fish and wildlife restoration, irrigation assistance,
and the provision of power to residential and small farm consumers.
We have also added a statement to the report's background section
indicating that these responsibilities are the result of
congressional mandates.
Additionally, the report describes in some detail fish costs, the
related Memorandum of Agreement that is intended to help control
those costs, and the annual magnitude of these costs. Specifically,
the report describes the uncertainty with regard to whether the
Memorandum of Agreement will be continued beyond 2001 as a factor
increasing BPA's risk during the post-2001 period. The report also
discloses that BPA paid $196 million in fiscal year 1996 to provide
power to selected residential and small farm consumers and recognizes
that BPA has an obligation totaling more than $800 million for
irrigation debt.
3. Although we agree that BPA's fish costs constitute significant
financial exposure, we do not concur with BPA's statement that they
constitute the "greatest financial exposure apart from market
prices." This statement ignores BPA's significant debt service
obligations and the projected upward pressure on other operating
costs. These costs, as the report discusses, significantly limit
BPA's financial flexibility and its ability to meet competitive
challenges.
4. Our report measures the net financing costs of debt outstanding
at September 30, 1996. This debt was incurred by BPA from 1951 to
1996; therefore, using the interest rate for Treasury's overall bond
portfolio, which includes bonds issued by Treasury over the last 30
years, is appropriate. We agree that this rate does not and should
not reflect "current Treasury borrowing costs nor the rates at which
Treasury lends to agencies."
5. We disagree. As a result of our analysis, we estimate that the
fiscal year 1996 net financing cost to the federal government
resulting from BPA's appropriated debt is $377 million. As discussed
in the agency comments section of volume 1, the 9.0 percent interest
rate on Treasury's outstanding portfolio of long-term bonds is the
appropriate interest rate to use in estimating the federal
government's net financing cost because it compares long-term debt to
long-term debt. However, even if we had used the 6.7 percent
interest rate proposed by BPA, the estimated fiscal year 1996 net
financing cost to the federal government is $223 million, which
represents a substantial cost to the federal government.
6. We believe that BPA's "high interest rate environments" assertion
is negated by its ability to pay off high interest rate debt first.
As a result, BPA's average interest rate on appropriated debt at
September 30, 1996, was 3.5 percent. This low average interest rate
results because very little appropriated debt incurred during "high
interest rate environments" is currently outstanding. Over 81
percent of BPA's currently outstanding appropriated debt is at rates
below 3.5 percent.
7. We discussed with cognizant Treasury officials BPA's assertion
that the interest rates it paid on its Treasury bonds result in a
markup of roughly 60 to 100 basis points over Treasury's borrowing
costs. These officials disagreed with this assessment and noted that
the difference between Treasury's borrowing costs and the rate BPA
paid on its Treasury bonds is due primarily to the differences in the
provisions of the borrowing terms under which each entity obtains
funds. Many of BPA's Treasury bonds carry provisions which allow BPA
to call the debt prior to its maturity, while the long-term bonds
issued by Treasury generally carry no call provisions. As a result,
Treasury bears additional interest rate risk as part of these
transactions. According to Treasury officials, these provisions in
BPA's Treasury bonds increase their value to BPA and require a higher
interest rate to compensate Treasury for its increased risk. Thus,
we continue to believe that the interest rate BPA paid on its
Treasury bonds results in a reasonable approximation of the federal
government's cost of providing the funds.
8. The characterization of BPA's appropriated debt as of the end of
fiscal year 1996 and the weighted-average interest rate associated
with this appropriated debt were taken directly from the audited
financial statements included in BPA's 1996 annual report. The
difference between BPA's appropriated debt after its restructuring as
shown in our draft report and the figure reported by BPA here relates
to the treatment of construction work in progress. Further
discussion with BPA staff indicates that the correct appropriated
debt balance is $4.29 billion. We have changed our report to reflect
this amount.
9. Our review of TVA and BPA appropriated debt entailed an
examination of whether or not the Treasury was receiving a return
sufficient to cover its borrowing costs. Unlike BPA, the terms of
TVA's appropriated debt require payment of market interest rates on
all of its appropriations, whether or not they are to be repaid to
the Treasury. These rates are reset on an annual basis. For
example, in 1982, because of high inflation and resultant high
interest rates, TVA's weighted-average interest rate on its
appropriated debt was over 12 percent, while BPA's was approximately
3.3 percent. In 1996, TVA paid an interest rate of approximately
6.87 percent, while BPA's weighted-average interest rate was about
3.5 percent. Because TVA is required to pay these market rates of
interest, which are re-set to Treasury rates every year, the Treasury
is receiving a return sufficient to cover its borrowing cost.
10. We agree that the marketplace is likely to become increasingly
competitive and that BPA will be subject to considerable market risk
in the future. This risk was discussed extensively in our report,
and was a primary factor in the report's risk analysis. We agree
that the prices BPA will be able to charge in the future will be
driven by market prices; the question is whether the revenues
received will be adequate to recover all of BPA's costs. After 2001,
considerable uncertainty exists with regard to market prices,
customer contract extensions, and the level of BPA's costs--giving
rise to our report's conclusion that the risk of loss to the federal
government after 2001 is "reasonably possible."
11. Our draft report stated that the federal government would have
financial losses if BPA (or the other entities reviewed) was unable
to repay debt owed to the federal government. We do not state that
the entire federal government's financial involvement is likely to be
lost. In addition, we added a comment to volume 1 of the final
report indicating that the power-related assets of BPA or the other
entities would be available to the federal government to sell to
offset some portion of any actual losses the federal government
incurred as a result of its financial involvement with these
entities.
12. We agree that there is uncertainty with regard to implementation
of the Comprehensive Review's recommendations. Since these
recommendations have not been implemented, we did not assess the
possible effect that they would have on the federal government's
financial risk.
13. We continue to believe that BPA's (and the other PMAs') ability
to repay the highest interest bearing debt first constitutes a major
advantage. This practice has allowed the PMAs (including BPA) to
keep the weighted-average interest rate on appropriated debt at
levels that are substantially below any Treasury market interest
rates that have been in effect for decades. BPA's fiscal year 1996
average interest rate on appropriated debt of 3.5 percent is evidence
of the benefit of the repayment provisions.
14. As stated in our report, we compared wholesale average revenue
per kWh for all entities.
(See figure in printed edition.)Appendix XIII
COMMENTS FROM THE TENNESSEE VALLEY
AUTHORITY
========================================================== Appendix IX
(See figure in printed edition.)
(See figure in printed edition.)
(See figure in printed edition.)
(See figure in printed edition.)
(See figure in printed edition.)
The following are GAO comments on TVA's letter dated July 10, 1997.
GAO COMMENTS
1. We agree that TVA's power program is costing the federal
government about $0.7 million per year for a portion of the pension
cost for the TVA employees covered by the federal Civil Service
Retirement System (CSRS). However, we did not analyze every aspect
of TVA's program to determine the total cost of TVA to the federal or
state governments. As agreed with the requesters and as pointed out
in both volume 1 and appendix II of volume 2 of our report, our
review did not (1) estimate the foregone revenue for federal, state,
or local governments resulting from the tax-exempt status of TVA, (2)
estimate the foregone revenue for federal and state governments
resulting from tax-exempt debt instruments issued by TVA, or (3)
quantify the amount of potential future losses to the federal
government. Therefore, we are able to state only that for those
costs we analyzed, TVA's power program does not result in costs to
the federal government, except for a small portion of the pension
costs of TVA employees covered by the CSRS.
2. We disagree. As noted in TVA's comments, as of September 30,
1996, TVA considered the government's equity in TVA to be
approximately $4 billion. This amount consisted of about $608
million in appropriation investment\1 (referred to as appropriated
debt in our report) and about $3.4 billion in retained earnings.\2
Using this definition of the federal government's equity, the federal
government's "capital invested in TVA prior to 1959" would have been
limited to the appropriation investment and retained earnings. TVA
does not pay the federal government an annual return (interest
income) on its retained earnings. It pays an annual return on the
government's appropriation investment only. The method for
calculating this return ensures that the annual payments made by TVA
result in a return to the federal government that covers its
borrowing costs. TVA's comments tend to support our position. TVA
stated, "Because the rate at which the annual return payment is
calculated equals the Treasury's current average cost of money, TVA
costs the taxpayers nothing."
3. Discussed in the "Agency Comments and Our Evaluation" section of
the letter in volume 1.
4. We concur that TVA is required to follow the federal regulations
that govern the employer and employee contributions for the CSRS and
therefore, has no control over the pension contribution rules for its
employees that are covered by this pension plan. As noted in
appendix II, in fiscal year 1996, OPM reported that the full (normal)
cost to the federal government of the pension benefits earned by CSRS
employees was 25.14 percent of gross salaries. However, since TVA is
required to contribute 7 percent and TVA's employees are required to
contribute another 7 percent, a funding deficiency of 11.14 percent
(25.14 less 14 percent) of annual salaries existed for each CSRS
employee. Since all new federal employees are covered by the FERS
pension plan, which is fully funded, the future cost to the federal
government of TVA's CSRS employees should continue to decline. We
also concur that the passage of any legislation to increase the
contributions of the employees and/or employers would decrease the
cost to the federal government of TVA's CSRS employees. However,
because of the present funding shortfall for the CSRS pension plan,
TVA, like most other government agencies, is not recovering the full
pension cost for the TVA employees covered by CSRS.
5. We agree with TVA that our assessment of the likelihood of loss
did not consider proceeds that the federal government might receive
from the sale of TVA's assets. We discuss this limitation in the
scope of our review in appendix II of volume 2 of our report. We
have added a note to table 3 in volume 1 of our report stating that
the federal government could sell the power-related assets of RUS
borrowers, the PMAs, and TVA to offset some portion of any actual
losses the federal government might incur as a result of its
financial involvement with these entities.
6. We believe the prospects for TVA completing the deferred units as
nuclear facilities is unlikely, especially given TVA's recently
issued 10-year business plan that provides no funding for completion
of these plants. Even if these units are converted to an alternative
fuel source, the potential savings over the construction of a new
plant are very small. Thus, most of the costs from the deferred
units are sunk and will not be utilized as nuclear plants or
converted power plants. It is unlikely that most, if any, of the
costs incurred on the deferred units to date will be used directly to
generate electricity. Therefore, we continue to believe that TVA
should apply SFAS No. 90 to the deferred nuclear assets and begin to
recover these costs immediately.
If TVA delays recovering the $6.3 billion, while it retains the
monopoly-like protections described in this report, it could end up
having to recover these costs from ratepayers when it is facing a
competitive environment and may not have the ability to set rates at
a level sufficient to recover all of these costs. Therefore, TVA's
continued exclusion of these costs from charges to ratepayers reduces
the likelihood of recovery from ratepayers and puts the federal
government at increased risk of absorbing these costs in the future.
7. We agree with the facts as stated by TVA, and we believe this
information supports our point that TVA is subject to interest rate
risk. Our report points out that as TVA's approximately $28 billion
in debt matures, the portion that is not repaid will likely need to
be refinanced, thus exposing TVA to the risk of rising interest rates
and even higher financing costs. As of September 30, 1996, TVA had
approximately $8 billion in long-term debt that will mature and need
to be refinanced over the next 5 years. By the end of this 5-year
period, for every 1 percentage point change in TVA's borrowing costs
for that $8 billion, its annual interest expense will increase or
decrease by $80 million per year. We also agree with TVA that its
approximately $2 billion in short-term debt represents additional
interest rate risk. We have revised our report to reflect this fact.
8. Our report points out that TVA has an inherent cost advantage
because it operates as a nonprofit and pays substantially less taxes
than its likely competitors--IOUs. We agree that as a nonprofit
operation, TVA would pay little or no income taxes because it has
minimal net income. However, the real underlying advantage TVA has
over IOUs is that it does not have to include a rate of return, which
results in taxable income, in its electricity rates. This allows TVA
to keep its rates proportionately lower than if a rate of return had
to be generated through revenues.
TVA also mentioned that to fairly compare the taxes paid by TVA to
IOUs we should include the taxes paid by TVA's distributors. We
agree and have revised our report to reflect this information. By
including the taxes paid by TVA's distributors, the percent of taxes
paid by TVA and its distributors in fiscal year 1995 was about 6
percent of gross power revenue, which is still substantially less
than the average annual taxes paid by IOUs.
9. The primary objectives of our report were to (1) identify the net
recurring cost to the federal government from its electricity-related
activities and (2) assess the risk of future loss to the federal
government from its indirect and direct involvement in RUS, the PMAs,
and TVA. We agree with TVA that as of September 30, 1996, it had
taken steps to provide adequate funding for two of its significant
long-term liabilities--decommissioning costs and pensions.
Therefore, there was no need to include these liabilities in our
discussion of the net cost to the federal government or risk of
future losses due to the federal government's involvement in TVA.
However, TVA's funding for the actual liabilities of these programs
is contingent upon the accuracy of their assumptions and the extent
to which future events conform to the schedule used in the
assumptions.
--------------------
\1 TVA's appropriation investment primarily represents appropriations
received from the federal government prior to 1959 to build capital
projects. The 1959 amendments to the TVA Act required TVA to begin
(1) repaying about $1 billion of the balance of this account and (2)
paying the federal government an annual market rate of return on the
unpaid portion of the balance.
\2 Retained earnings represent the cumulative revenue in excess of
accrued expenses. These earnings have been used by TVA primarily to
finance capital assets.
MAJOR CONTRIBUTORS TO THIS REPORT
========================================================= Appendix XIV
ACCOUNTING AND INFORMATION
MANAGEMENT DIVISION, WASHINGTON,
D.C.
Gregory D. Kutz, Associate Director
McCoy Williams, Assistant Director
Robert E. Martin, Senior Audit Manager
Donald R. Neff, Senior Audit Manager
Dianne Langston, Audit Manager
Patricia B. Petersen, Auditor
Meg Mills, Communications Analyst
OFFICE OF THE GENERAL COUNSEL,
WASHINGTON, D.C.
Thomas H. Armstrong, Assistant General Counsel
Amy M. Shimamura, Senior Attorney
ATLANTA FIELD OFFICE
William J. Cordrey, Senior Auditor
Johnny W. Clark, Auditor
Marshall L. Hamlett, Auditor
KANSAS CITY FIELD OFFICE
Arthur W. Brouck, Senior Auditor
Christie M. Arends, Auditor
Gary T. Brown, Auditor
Karen A. Rieger, Auditor
SEATTLE FIELD OFFICE
David W. Bogdon, Senior Evaluator
Laurence L. Feltz, Senior Evaluator
*** End of document. ***