Tennessee Valley Authority: Financial Problems Raise Questions About
Long-Term Viability (Chapter Report, 08/17/95, GAO/AIMD/RCED-95-134).
The Tennessee Valley Authority (TVA) is $26 billion in debt and has
invested $14 billion in nonproducing nuclear assets that are not
included in its electricity rates. As a result, TVA has far more
financing costs and deferred assets than its likely competitors have,
which gives TVA little flexibility to meet competitive challenges. To
the extent that TVA cannot compete effectively and improve its financial
condition, the federal government may have to pick up the tab for some
of TVA's debt. TVA's troubled financial condition has been caused
largely by construction delays, cost overruns, and operational shutdowns
in its nuclear program. TVA's links to the federal government and its
high debt limit have allowed it to borrow the billions of dollars needed
for its nuclear construction program. Although no cash crisis exists
today, GAO believes that TVA's financial condition threatens its
long-term viability and places the federal government at risk. GAO
highlights several options that could reduce risk to federal taxpayers
and help prepare TVA to compete in the electricity market.
--------------------------- Indexing Terms -----------------------------
REPORTNUM: AIMD/RCED-95-134
TITLE: Tennessee Valley Authority: Financial Problems Raise
Questions About Long-Term Viability
DATE: 08/17/95
SUBJECT: Electric utilities
Utility rates
Electric power generation
Federal corporations
Energy costs
Energy law
Financial management
Internal controls
Competition
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Cover
================================================================ COVER
Report to Congressional Requesters
August 1995
TENNESSEE VALLEY AUTHORITY -
FINANCIAL PROBLEMS RAISE QUESTIONS
ABOUT LONG-TERM VIABILITY
GAO/AIMD/RCED-95-134
Tennessee Valley Authority
Abbreviations
=============================================================== ABBREV
COMMEND - Commercial End-Use Energy Planning System
DOE - Department of Energy
DRI - Data Resources, Inc.
EFM - Electricity Forecasting Model
ELCON - Electricity Consumers Resource Council
FERC - Federal Energy Regulatory Commission
FFB - Federal Financing Bank
FINESSE - financial model
GAAP - generally accepted accounting principles
GAO - General Accounting Office
HELM - Hourly Energy Load Model
INFORM - Industrial Energy End-Use Model
IPP - independent power producer
IOU - investor-owned utility
IRP - integrated resource plan
kwh - kilowatt hour
MW - megawatt
NRC - Nuclear Regulatory Commission
PP&E - property, plant, and equipment
REEPS - Residential End-Use Energy Planning System
RESM - Regional Economic Simulation Model
SFAS - Statement of Financial Accounting Standards
TVA - Tennessee Valley Authority
TVPPA - Tennessee Valley Public Power Association
Letter
=============================================================== LETTER
B-259411
August 17, 1995
Congressional Requesters
As requested, this report presents the results of our review of the
Tennessee Valley Authority's (TVA) financial condition. Our report
provides information and analyses on the implications of TVA's
financial condition for TVA and the federal government in light of
the increasingly competitive electric utility market. This report
discusses several options available for TVA and congressional
decisionmakers in deciding what types of financial and other changes
may be needed to protect the interests of all those, including the
taxpayer, who have a stake in TVA's future.
As arranged with your offices, unless you publicly announce the
contents of this report earlier, we will not distribute it until 7
days from the date of this letter. At that time, we will send copies
to appropriate House and Senate committees, interested Members of the
Congress, the Chairman of TVA's Board of Directors, the Director of
the Office of Management and Budget, and other interested parties.
We will also make copies available to others upon request.
This report was prepared under the direction of Lisa Jacobson,
Director, Civil Audits in the Accounting and Information Management
Division, who may be reached at (202) 512-9508, and Victor S.
Rezendes, Director of Energy and Science Issues in the Resources,
Community, and Economic Development Division, who may be reached at
(202) 512-3841, if you have any questions. Major contributors to
this report are listed in appendix VI.
Gene L. Dodaro
Assistant Comptroller General
Accounting and Information
Management Division
Keith O. Fultz
Assistant Comptroller General
Resources, Community, and
Economic Development Division
List of Requesters
The Honorable Bud Shuster
Chairman
The Honorable Norman Y. Mineta
Ranking Minority Member
Committee on Transportation and Infrastructure
House of Representatives
The Honorable John R. Kasich
Chairman
Committee on the Budget
House of Representatives
The Honorable Howell Heflin
United States Senate
The Honorable Trent Lott
United States Senate
The Honorable Bob Clement
House of Representatives
The Honorable Bud Cramer
House of Representatives
The Honorable John J. Duncan, Jr.
House of Representatives
The Honorable James H. Quillen
House of Representatives
The Honorable Zach Wamp
House of Representatives
EXECUTIVE SUMMARY
============================================================ Chapter 0
PURPOSE
---------------------------------------------------------- Chapter 0:1
The Tennessee Valley Authority (TVA), established in 1933 as a
multipurpose, independent, government-owned corporation, is one of
the nation's largest utilities. In March 1994, the Subcommittee on
Investigations and Oversight of the House Committee on Public Works
and Transportation held a hearing on TVA that raised concerns about
TVA's nuclear program and its financial condition--including the
growth of TVA's debt toward the $30 billion ceiling established by
the Congress in 1979. At the request of several Members of the
Congress, GAO examined the implications for TVA and possibly the
federal government of TVA's financial condition in light of the
increasingly competitive electric utility market. More specifically,
this report presents information on TVA's financial condition
compared with neighboring utilities, power resource decisions,
competitive prospects in the short term, and options for addressing
TVA's problems.
BACKGROUND
---------------------------------------------------------- Chapter 0:2
TVA is a unique federal corporation that supplies electricity and
develops resources to serve more than 7 million people in an
80,000-square-mile area covering Tennessee and parts of Alabama,
Georgia, Kentucky, Mississippi, North Carolina, and Virginia.
TVA's multibillion-dollar power program, which generated about $5.4
billion in 1994 revenues, is required by the Tennessee Valley
Authority Act to be self-supporting from power revenues. TVA issues
bonds to provide most of the financing needed to construct its power
facilities. Under section 15d of the TVA Act, these bonds are not
guaranteed by the federal government. However, the financial
community views them as having an implicit federal guarantee.
Existing legislation also gives TVA a great deal of independence in
deciding how it is to be operated and managed. TVA's three-member
Board of Directors has the sole authority to set electricity rates
for its 160 distributors and decide what kinds of power plants to
build.
Because of protections provided in legislation and contracts with its
distributors, TVA generally has not had to compete with other
utilities. TVA has recently acknowledged through its actions and
announcements that it will have to compete in the future. In
addition, industry experts have stated that TVA's service area cannot
remain isolated from competition.
RESULTS IN BRIEF
---------------------------------------------------------- Chapter 0:3
TVA is $26 billion in debt and has invested $14 billion in
nonproducing nuclear assets (called "deferred assets") that are not
included in its electricity rates. As a result, TVA has far more
financing costs and deferred assets than its likely competitors have,
which gives TVA little flexibility to meet competitive challenges.
To the extent that TVA cannot compete effectively and improve its
financial condition, the federal government is at risk for some
portion of TVA's debt.
TVA's troubled financial condition has been largely caused by
construction delays, cost overruns, and operational shutdowns in its
nuclear program. Because TVA has excluded the costs of its
nonproducing nuclear assets from its electricity rates for a long
period, its current rates are too low to recover all relevant costs.
To complete its nuclear construction activities and modernize its
coal and hydroelectric plants, TVA will have to spend billions of
dollars more, adding further pressure to increase electricity rates.
TVA's links to the federal government and its high debt limit have
enabled it to borrow the billions of dollars needed for its nuclear
construction program. TVA's electricity rates and power production
decisions are not subject to the same oversight that other utilities
routinely face. Although protected from competition by legislation
and its customer contracts in the short run, TVA will have to compete
with other utilities in the long run. Because of its heavy debt
burden and resultant high financing costs, TVA lacks the flexibility
to successfully compete in this environment.
While no cash-flow crisis exists today, GAO believes that TVA's
financial condition threatens its long-term viability and places the
federal government at risk. Resolving TVA's financial problems will
be costly and require painful decisions. GAO is highlighting several
options that could reduce risk to federal taxpayers and help prepare
TVA to compete in the electricity market.
GAO'S ANALYSIS
---------------------------------------------------------- Chapter 0:4
TVA'S FINANCIAL CONDITION
PUTS IT AT A COMPETITIVE
DISADVANTAGE
-------------------------------------------------------- Chapter 0:4.1
Compared with neighboring utilities, TVA's financial
condition--especially its high financing costs and deferred
assets--places it at a competitive disadvantage. For example, TVA's
high debt resulted in its paying $1.9 billion, or 35 percent of its
power revenues in 1994, for financing costs. Similar expenses for
TVA's neighboring utilities averaged only 16 percent of revenues.
Furthermore, 69 percent of TVA's $28 billion of net property, plant,
and equipment was related to the nuclear program, which generated
only 14 percent of TVA's electricity in 1994. In contrast, only 19
percent of these assets were related to TVA's coal and hydroelectric
programs, which generated almost 86 percent of TVA's electricity.
Among other factors, TVA's decisions to defer from its electricity
rates the costs for nonproducing nuclear assets that do not generate
electricity or produce revenue have permitted TVA to maintain stable
electricity rates since 1988. When these costs are recognized,
pressure to increase TVA's rates appears likely, despite recent
management steps to reduce TVA's operating costs. These steps,
including a substantial reduction in employees and refinancing of
debt, leave little room for TVA to further reduce its controllable
costs. TVA has recognized the problems created by high debt. In
December 1994, TVA announced plans to limit its debt to about $2
billion to $3 billion below the $30 billion ceiling and to reach this
limit by the end of fiscal year 1997.
In contrast to TVA, neighboring utilities have far less financing
costs and deferred assets. These two factors provide neighboring
utilities with greater flexibility to meet price competition. For
example, in 1994, TVA's ratio showing costs deferred from current
rates to be recouped in the future was more than 15 times higher than
the average ratio for neighboring utilities. Furthermore, despite
having excluded its deferred assets, TVA's rates, while low, are not
the lowest compared to neighboring utilities.
TVA'S POWER RESOURCE
DECISIONS INCREASE
FINANCIAL, OPERATING, AND
COMPETITIVE RISKS
-------------------------------------------------------- Chapter 0:4.2
TVA's nuclear power program has had a long history of construction
and operating problems. For example, one unit currently under
construction--Watts Bar 1--is expected to cost $6.8 billion at
completion and has been under construction for over 22 years.
Another unit--Browns Ferry 3--went into commercial service in 1977,
was shut down in 1985, and is not expected to be restarted until
1996. Furthermore, the total estimated costs to bring Watts Bar 1
and Browns Ferry 3 into commercial operation increased about $1.6
billion and $1.2 billion, respectively, between fiscal years 1990 and
1994. In addition, TVA has $6.2 billion in deferred assets
associated with three nuclear units that are currently in a
"mothballed" status.
Because of changing market conditions and uncertain levels of demand
for electricity, many utilities are investing in alternative power
resource options. Many other utilities are planning to meet their
future power needs by building lower cost natural gas fired units or
purchasing power from outside sources. During fiscal year 1994, TVA
spent $2 million a day at Watts Bar 1 and Browns Ferry 3. TVA also
anticipates spending from $240 million to $301 million annually (in
constant 1994 dollars) for the next 26 years to upgrade its aging
coal and hydroelectric plants. TVA will continue to rely on these
coal and hydroelectric plants to produce most of its electricity.
Further delays and cost overruns at its nuclear units could limit
funds available for needed improvements to these plants.
TVA'S COMPETITIVE PROSPECTS
ARE PROTECTED IN THE SHORT
RUN
-------------------------------------------------------- Chapter 0:4.3
Although TVA's financial condition is troubled, in the short run TVA
is protected from the pressures of competition. For example, in
nearly all instances, contracts with TVA's 160 distributors require
that a 10-year notice be given before they can switch to another
power company. Also, TVA is not required under existing legislation
to allow other utilities to use its transmission lines to provide
service to TVA's customers.
However, even these protections do not guarantee that TVA will remain
isolated from competition. For instance, because they are concerned
about potential rate increases, some of TVA's distributors have
solicited and received bids to buy power from other suppliers.
Furthermore, industrial representatives said that TVA needs to reduce
its rates to be competitive with the low-cost utilities in the
region.
An April 1995 report commissioned by TVA concluded that TVA is
well-positioned to meet competitive challenges because its financial
condition is sufficiently flexible and strong. The report
recommended a phased approach to remove legislative restrictions so
TVA could become fully competitive.
While agreeing that TVA will have to compete in the future, GAO
disagrees that TVA's financial condition will allow it to compete
successfully. Furthermore, GAO disagrees that removing existing
legislative protections would make TVA more competitive at this time.
On the contrary, these protections keep TVA from being placed in a
position where competition could adversely affect its long-term
financial viability.
OPTIONS FOR ADDRESSING TVA'S
PROBLEMS
-------------------------------------------------------- Chapter 0:4.4
TVA has taken various actions and has announced other plans to reduce
its costs and limit its debt to make itself more competitive.
However, GAO does not believe that these actions will be sufficient
in the long term to adequately protect the interests of federal
taxpayers and enable TVA to meet competitive challenges. TVA does
not face a cash-flow problem today only because it has nearly $4
billion of remaining borrowing authority.
A number of options are available to address TVA's financial
problems. For example, TVA could raise rates. With the additional
cash generated from operations, TVA could reduce its borrowing or pay
down its debt; however, this course of action would make TVA's rates
less competitive, thus aggravating its long-term financial health.
The Congress also has a broad range of options. For example, the
Congress could allow TVA to continue to try and work the problems out
on its own, remove statutory barriers to competition, or privatize
TVA. Each of these options would involve tradeoffs. The Congress
could also forgive TVA's federal debt or restructure some or all of
its debt so that TVA repays at a lower interest rate. These options
would have a negative impact on the federal deficit. And the
Congress could subject TVA to greater management oversight by
requiring that its rates and resource decisions be reviewed and
approved by an external body, or by expanding its Board to include a
broader spectrum of interests.
These and other options that are discussed in this report are not
intended to suggest a specific course of action but rather to provide
a basis for discussion on how to protect the interests of everyone
who has a stake in TVA's future.
AGENCY COMMENTS
---------------------------------------------------------- Chapter 0:5
TVA strongly disagreed with GAO's assessment in many areas. TVA
officials stated that TVA is a financially healthy corporation that
is well able to service its debt now and in the future. TVA
officials further stated that it has made the tough decisions
necessary to prepare for the coming era of deregulation and
competition in the utility industry.
GAO agrees that TVA has taken a number of actions in recent years to
improve its financial position, including downsizing its work force
and refinancing its debt at lower interest rates. These actions,
however, do not significantly diminish the financial problems
identified in this report that raise questions about TVA's long-term
viability. As a result, GAO continues to believe that TVA has little
flexibility to meet the competitive challenges that lie ahead; and to
the extent that TVA cannot compete effectively and improve its
financial condition, the federal government is at risk for some
portion of TVA's debt. For these reasons, GAO continues to believe
that a dialogue is needed among the key decisionmakers concerning
options available to better protect the government's interests and
help TVA fulfill its announced intention of becoming a competitive
and financially viable utility.
TVA's written comments are presented in appendix IV, and GAO's
responses are discussed in chapter 5 and appendix IV.
INTRODUCTION
============================================================ Chapter 1
The Tennessee Valley Authority (TVA) is a multipurpose, independent,
federal corporation established by the Tennessee Valley Authority Act
of 1933. 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. Today, TVA operates one of the nation's largest power
systems, with a dependable capacity in service of about 26,000
megawatts (MW).\1 The system consists primarily of 113 hydroelectric
units, 59 coal-fired units, and 3 operating nuclear units. TVA sells
power in seven states--Alabama, Georgia, Kentucky, Mississippi, North
Carolina, Tennessee, and Virginia--as illustrated in figure 1.1.
Figure 1.1: Map of TVA's
Service Area
(See figure in printed
edition.)
Source: TVA 1994 Annual Report.
TVA sells power at wholesale rates to 160 municipal and cooperative
distributors and to a number of directly served large industrial
customers and federal agencies. These distributors, in turn, sell
the power on a retail basis to more than 7 million people in an
80,000 square mile region. TVA had about 19,000 employees on
September 30, 1994. TVA's power program generated about $5.4 billion
in 1994 revenues, with about $4.6 billion of this amount coming from
the 160 distributors.
TVA's programs are divided into two types of activities--the nonpower
programs and the power program. The nonpower programs, such as water
resources, navigation, and flood control, are primarily funded
through federal appropriations and user fees. These programs
received about $140 million in funding in fiscal year 1994 and are
operated primarily within the 41,000 square mile Tennessee River
watershed. TVA's power program is included in the federal budget as
a public enterprise revolving fund called the TVA Fund. Revolving
funds are generally intended to be self-supporting, such that their
operating expenses are paid for by operating revenues.
--------------------
\1 A megawatt is one million watts of electricity.
AUTHORIZING LEGISLATION
ESTABLISHED TVA AS A WHOLLY-
OWNED GOVERNMENT CORPORATION
---------------------------------------------------------- Chapter 1:1
TVA's authorizing legislation allows it to operate with a high degree
of independence. The TVA Act of 1933 did not subject TVA to the
regulatory and oversight requirements that must be satisfied by other
power administrations or electric utilities. For example, unlike
other utilities, the rates TVA charges for its electric power and its
power resource decisions are not subject to review and approval by
state public utility commissions or the Federal Energy Regulatory
Commission (FERC).
Under existing legislation, FERC is primarily responsible for (1)
regulating rates, terms, and conditions for the sale and transmission
of electricity sold at wholesale in interstate commerce, (2)
regulating mergers, dispositions, and acquisitions of facilities used
for the transmission of electricity in interstate commerce or the
sale of wholesale power in interstate commerce (referred to as
jurisdictional facilities), and (3) authorizing the issuance of
securities in those instances where states do not regulate them.
Existing legislation requires that rates for wholesale electric
energy sales and for the transmission of electric energy in
interstate commerce be "just and reasonable," without undue
preferences or advantages to buyer or seller. State public utility
commissions are primarily responsible for approving retail
electricity rates and resource decisions for utilities under their
jurisdiction.
In recent years, both federal and state regulators have acted to
promote competition in wholesale electricity markets. For example,
FERC has approved wholesale electricity rates that were market based
(determined through a competitive or negotiated process between the
purchasing utility and the potential supplier). Previously, FERC
generally approved rates only if they were cost based (based on the
seller's cost of supplying power).
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.\2 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.
The issue of TVA's oversight has been examined several times in the
past. For example, in a 1982 report, we pointed to a growing concern
with TVA activities and identified options for improving oversight
and accountability.\3 These options included periodic congressional
oversight hearings and/or placing the TVA rate-setting process under
FERC. In a 1983 report, we reported on our concerns about TVA's
management and concluded that the issue of the adequacy of TVA's
oversight needed greater attention.\4 In a 1987 report entitled
"TVA--A Path to Recovery," the Southern States Energy Board\5
concluded that "...additional mechanisms are needed to ensure that
TVA is accountable for its actions to its ratepayers, Congress, and
the American public." The report further stated that "There must be a
fundamental change in TVA's structure to effectively respond to
today's challenges and meet the necessary standards of
accountability. A larger Board should be established, comprised of
part-time directors who would be responsible for policy-making and
oversight of TVA's management."
In 1959, the Congress amended the TVA Act to authorize the use of
debt financing to pay for capital improvements for power programs.
Under this legislation, the Congress required that TVA's power
program be "self-financing" through revenues from electricity sales.
For capital needs in excess of internally generated funds, TVA was
authorized to borrow by issuing bonds. TVA's debt limit is set by
the Congress and was established at $750 million in 1959. 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.
The 1959 amendments to the TVA Act also protected 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 act 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 sell power to 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.
--------------------
\2 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.
\3 Tennessee Valley Authority--Options for Oversight (GAO/EMD-82-54,
Mar. 19, 1982).
\4 Triennial Assessment of the Tennessee Valley Authority--Fiscal
Years 1980-1982 (GAO/RCED-83-123, Apr. 15, 1983).
\5 The Board was comprised of government and industry experts with
diverse experience in energy operations, management, and regulation.
LEGISLATIVE CHANGES CREATE A
COMPETITIVE ELECTRICITY MARKET
FOR OTHER UTILITIES
---------------------------------------------------------- Chapter 1:2
Historically, investor-owned utilities (IOU) and other electricity
providers have operated as regulated monopolies. Under traditional
utility regulation, electric utilities' rates and investments in
generation, transmission, and distribution facilities were regulated
by state public utility commissions. Under these arrangements, IOUs
were required to provide electric service to all customers within
their power service areas. In exchange, they received exclusive
service areas. To serve their customers, utilities could incur costs
for building new generating plants and operating the power system.
IOUs generally recoup these costs plus a regulated return through
their electricity rates.
In the last 25 years, laws have encouraged the creation of a
competitive market. The Public Utilities Regulatory Policies Act of
1978 facilitated the creation of small (less than 80 MW of capacity)
electricity generators that were exempt from many state and federal
regulations. Called "nonutility generators" or "independent power
producers" (IPP),\6 these entities typically used new technologies to
generate power, such as cogenerating plants\7 or small natural gas
fired generation units. According to the National Independent Energy
Producers,\8 by the end of 1994, these entities accounted for about
51,000 MW of capacity in the United States (or about 6 percent of
total capacity in the nation)--directly competing with utility-owned
capacity and placing downward pressures on electricity rates.
Today, many IPPs pose a threat to IOUs, in part because IPPs can
establish generation facilities near large industrial and municipal
customers and sell power to these customers for a lower rate than the
established utility. For example, in upstate New York, an IPP is
building a 1,000 MW cogeneration plant next to two industrial plants,
thereby luring away from the established utility one of its largest
customers as well as a smaller one. The IPP plans to sell 65 MW to
the two industrial customers and its remaining power to other
utilities.
The Energy Policy Act of 1992 promoted increased competition in the
electricity market. The act encouraged open transmission of
electricity by allowing wholesale electricity customers, such as
municipal distributors, to purchase electricity from any supplier,
even if that power must be transmitted over lines owned by another
utility--referred to as wheeling of power.\9 Under the act's
provisions, FERC can compel a utility to transmit electricity
generated by another utility into its service area for resale.
However, the act protects TVA from the new wheeling requirements by
preventing competitors from using TVA's transmission system to sell
to customers inside TVA's service area. In addition, the act
required TVA to conduct a least-cost planning program--also referred
to as an integrated resource plan (IRP). For further information
about TVA's ongoing IRP process, see appendix I.
Electricity markets are becoming more competitive and, as a result,
FERC expects wholesale and retail electricity rates to drop. For
example, according to Virginia Power officials, a subsidiary of
American Electric Power offered to sell electricity to a rural
electric cooperative in Virginia--a wholesale customer of Virginia
Power. To retain this business, Virginia Power cut its rates by over
5 percent. State regulators are now exploring opportunities to make
retail markets competitive. Several states, including California,
Michigan, and Washington, are exploring whether to introduce "retail
wheeling"--a concept under which end-use customers will choose the
utility that provides them with electric power, much like consumers
today choose a long distance telephone company.
While TVA is currently exempt from wheeling requirements and has
other barriers to protect it from competition in the short term, it
has recently acknowledged through its actions and announcements that
it will have to compete in the future. Industry experts and
representatives of TVA's customers have also stated that TVA's
service area cannot remain isolated from competition over the long
run.
--------------------
\6 IPPs, which are firms that produce electric power to be sold at
wholesale rates, are not considered utilities because they do not
produce power for a service area and do not engage in transmitting or
distributing power.
\7 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.
\8 National Independent Energy Producers is a trade association
representing many nonutility generators of electricity and IPPs.
\9 Wheeling of power refers to the use of a utility's transmission
system when the power is being bought and sold by parties other than
the transmitting utility. Fees are paid to the transmitting utility
for use of its system.
HISTORY OF TVA'S NUCLEAR POWER
PROGRAM
---------------------------------------------------------- Chapter 1:3
TVA made its commitment to nuclear power in the late 1960s and early
1970s, when power sales were growing at a steady rate and were
expected to double every 10 years. In the Tennessee Valley, the
number of electricity customers rose to over 2 million in the 1960s
and about 30 percent of all the homes were heated with electricity.
By 1970, TVA customers used nearly twice as much electricity as the
national average. At that time, TVA was experiencing an annual
growth rate of about 8 percent in demand for electricity, and TVA's
forecasts through the mid-1970s were showing continued high growth in
demand.
TVA believed, along with many in the utility industry, that new
generating capacity was needed to satisfy its forecast demand. To
meet that need and lessen the environmental problems associated with
its coal plants, TVA embarked on a highly ambitious nuclear power
plant construction program. In 1966, TVA announced plans to build 17
nuclear units at seven sites in Tennessee, Alabama, and Mississippi.
In 1967, it started building the nation's largest nuclear power
facility--Browns Ferry in north Alabama.
However, instead of increasing, electricity consumption declined in
the mid-1970s following the 1973 energy crisis and again in the late
1970s and 1980s as a result of higher energy costs and lower economic
growth. Also, in 1975, after an electrical insulation fire damaged
the Browns Ferry plant and again in 1979 after the Three Mile Island
nuclear accident, NRC issued extensive new safety regulations that
applied to all plants, including those under construction or in
operation. The decreasing demand for electricity, coupled with the
increased regulation surrounding nuclear power, caused the electric
utility industry to rethink the role that nuclear power would play in
meeting the nation's demand for electricity.
By the early 1980s, most utilities had chosen to cancel ongoing or
planned nuclear plants. After reassessing its forecast demand using
a more sophisticated methodology, TVA began scaling back its nuclear
plans by canceling 8 of its 17 planned nuclear units in 1982 and 1984
after investing almost $5 billion\10 in the 8 units. The costs
associated with these plants were written off over 10 years and
recovered through rates.
TVA's nine remaining nuclear units have had a long history of
operating and construction problems. The status of these units as of
March 1, 1995, was as follows:
Three units were operational: Browns Ferry 2, Sequoyah 1, and
Sequoyah 2.
Two units were actively under construction: Watts Bar 1 has been
under construction for 22 years and has not yet operated.
Browns Ferry 3 began operations in 1977, but was shut down in
1985 because of repeated operational and maintenance errors.
Four units were in a "mothballed" status: Browns Ferry 1 was shut
down because of ineffective management and technical
deficiencies. Construction has been suspended indefinitely on
Watts Bar 2, Bellefonte 1, and Bellefonte 2. TVA plans to
maintain these units in their present status until completion of
its IRP in late 1995. At that time, it will consider such
alternatives as (1) converting the units to another technology
such as natural gas, (2) replacing them with different types of
supply- and demand-side resource options, (3) completing the
construction of one or more units as nuclear plants in
partnership with others, or (4) maintaining them in a mothballed
state pending a later decision.
Today, TVA is the only utility in the nation actively constructing
nuclear power plants. To date, its investment in nuclear units has
totaled about $25 billion, of which about $5 billion has been spent
on units that are now operating. Table 1.1 summarizes the current
status of TVA's nuclear program.
Table 1.1
Status of TVA's Originally Planned 17
Nuclear Units as of July 1995
Year Year
Nuclear plants/ construction commercial Current
units started service began status
--------------- ------------- ------------- -------------
Browns Ferry 1967 1974 shutdown\a
unit 1 1967 1975 operating
unit 2 1968 1977 construction\
unit 3 b
Sequoyah
unit 1 1970 1981 operating
unit 2 1970 1982 operating
Watts Bar
unit 1 1973 1996\c construction
unit 2 1973 none unfinished\a
Bellefonte
unit 1 1974 none unfinished\a
unit 2 1974 none unfinished\a
Phipps Bend
unit 1 1977 none cancelled
unit 2 1977 none 1982
cancelled
1982
Hartsville
A units 1&2 1976 none cancelled
B units 1&2 1977 none 1984
cancelled
1982
Yellow Creek
unit 1 1978 none cancelled
unit 2 1978 none 1984
cancelled
1984
------------------------------------------------------------
\a Considered to be in "mothballed" status.
\b Browns Ferry unit 3 was originally opened in 1977 and shut down in
1985. TVA plans to have the unit in full commercial operation by
February 1996.
\c TVA's estimated date of commercial operation is February 1996.
Source: GAO analysis of TVA data.
--------------------
\10 Unless noted otherwise, amounts in this report are in
current-year dollars.
OBJECTIVES, SCOPE, AND
METHODOLOGY
---------------------------------------------------------- Chapter 1:4
On March 9, 1994, the Subcommittee on Investigations and Oversight of
the House Committee on Public Works and Transportation held an
oversight hearing on TVA. The hearings focused on TVA's nuclear
power program, debt level, load forecasting, and resource planning
process. During these hearings, concerns were expressed about TVA's
ability to construct and operate its nuclear units reliably, the
impact of TVA's debt on its rates and competitiveness, and the
accuracy of TVA's load forecasts.
Because of concerns raised during and after the March 1994 hearing,
several Members of the House and Senate requested that we undertake
an examination of TVA. On the basis of subsequent briefings and
meetings with the requesters' offices, we agreed to examine the
implications for TVA and possibly the federal government of the
financial issues facing TVA in light of the increasingly competitive
electric utility market.
In this report, we present information and analyses on (1) TVA's
financial condition compared with neighboring utilities (in chapter
2), (2) TVA's power resource decisions (in chapter 3), (3) TVA's
short-term competitive prospects (in chapter 4), and (4) options for
addressing TVA's problems (in chapter 5). In response to other
issues raised, we also discuss TVA's integrated resource planning
process in appendix I, its past and present load forecasting
methodologies in appendix II, and its use of in-substance defeasance
to refinance debt in appendix V. Additional information on our
objectives, scope, and methodology, including a listing of the
various organizations and groups we contacted, is contained in
appendix III.
Where possible, we used audited fiscal year 1994 financial data for
TVA and the neighboring utilities. We conducted our review between
June 1994 and July 1995 in accordance with generally accepted
government auditing standards. We requested written comments from
the chairman of the Tennessee Valley Authority or his designee. TVA
provided written comments on a draft of this report. These comments
are reprinted in appendix IV.
TVA'S FINANCIAL CONDITION WILL
MAKE IT DIFFICULT TO COMPETE
============================================================ Chapter 2
As of September 30, 1994, TVA had about $26 billion of total debt.
This debt resulted in TVA paying $1.9 billion in financing costs,\1
which represented 35 percent of its revenues in fiscal year 1994. At
the same time, $14 billion of nonproducing nuclear assets\2 have not
been included in TVA's revenue requirements\3 and are thus excluded
from current rates. Inclusion of these costs in future revenue
requirements will likely increase TVA's rates.
TVA's financing costs and deferred assets\4 place it at a competitive
disadvantage when compared to the financial condition of surrounding
IOUs. IOUs have substantially less financing costs and deferred
assets than TVA. These factors provide the surrounding IOUs with
greater flexibility to meet rate competition. Despite having
excluded its deferred assets from current rates, TVA's rates are not
the lowest when compared with these surrounding IOUs.
--------------------
\1 Financing costs include interest expense on short- and long-term
debt, interest on appropriation investment (TVA only), and dividends
on preferred and common stock (IOUs only). Since TVA does not issue
stock, its financing costs consist of interest charges only.
Preferred and common stock dividends were included in the IOUs'
financing costs to reflect the difference in the capital structure of
these entities and TVA.
\2 TVA's nonproducing nuclear assets include investment in nuclear
units that are recorded in the construction in progress and deferred
nuclear units accounts on TVA's balance sheet. These units neither
generate electricity nor produce revenue.
\3 Revenue requirements refer to the amount of revenue necessary to
cover all operating expenses and debt service for TVA's power
program. Increases in revenue requirements will cause a rate
increase only if TVA cannot offset them. TVA projects its
requirements annually and uses this estimate as the basis for setting
electricity rates.
\4 In addition to its nonproducing nuclear assets, TVA has an
additional $2 billion of construction in progress involving
non-nuclear assets. For IOUs, deferred assets include only
construction in progress.
TVA HAS SUBSTANTIAL DEBT AND
SIGNIFICANT COSTS FOR
NONPRODUCING NUCLEAR ASSETS
---------------------------------------------------------- Chapter 2:1
TVA has financed its large nuclear investment primarily by issuing
debt (borrowing). Current rates must recover the substantial amount
of annual interest on this debt, including the portion related to
TVA's nonproducing nuclear assets. In addition, we estimate that
TVA's $14 billion of nonproducing nuclear assets will increase its
future revenue requirements by at least 9 percent.
LARGE INVESTMENT IN NUCLEAR
POWER ASSETS
-------------------------------------------------------- Chapter 2:1.1
On the basis of historic costs reflected in TVA's balance sheets,
since its construction program began in 1966, TVA has spent over $25
billion on nuclear assets. This includes the costs of eight
cancelled nuclear plants that were previously written off, along with
all other nuclear costs on TVA's balance sheet as of September 30,
1994. As stated in chapter 1, only 3 of the planned 17 units are
currently operating.
On September 30, 1994, TVA's power program had net assets of almost
$32 billion, ranking it in terms of assets as one of the largest
electric utilities in the United States. TVA's asset composition
reflects the capital intensive requirements of the electric utility
industry. Nearly 90 percent ($28.1 billion) of TVA's net assets were
classified as property, plant, and equipment (PP&E), including coal,
hydroelectric, and nuclear power units and transmission lines. Of
the $28.1 billion of net PP&E, $19.3 billion was invested in nuclear
power generation assets at September 30, 1994.
The substantial investment in nonproducing nuclear assets is evident
by comparing the residual investments, net of depreciation, in TVA's
various fuel sources with actual power generated, as shown in figure
2.1. Although investment in nuclear assets accounted for nearly 69
percent of TVA's net PP&E as of September 30, 1994, TVA's nuclear
units supplied only 14 percent of its total system power generation.
In contrast, TVA's coal and hydroelectric units accounted for nearly
19 percent of net PP&E on September 30, 1994, while supplying almost
86 percent of TVA's generated power.
Figure 2.1: TVA's $28 Billion
in Net Property, Plant, and
Equipment as of September 30,
1994, and Power Generation by
Fuel Source for Fiscal Year
1994
(See figure in printed
edition.)
Note: Assets are net of accumulated depreciation.
Source: TVA 1994 financial statements.
SUBSTANTIAL DEBT INCURRED
-------------------------------------------------------- Chapter 2:1.2
TVA finances its PP&E primarily with debt. As of September 30, 1994,
TVA had cumulatively financed 77 percent of its gross PP&E with debt.
In practice, TVA issues debt when its expenditures for PP&E exceed
the net cash it generates from operations. For example, in fiscal
year 1994, TVA's expenditures for PP&E were $2 billion while net cash
from operations amounted to about $1.1 billion. As a result, TVA's
total outstanding debt increased during 1994 by approximately $900
million.
As of September 30, 1994, TVA's debt consisted primarily of about
$22.2 billion of outstanding long-term debt, about $3.3 billion of
short-term debt, and approximately $0.4 billion of appropriated
debt.\5 This last form of debt represents funds appropriated or
property transferred by the federal government to TVA for power
facilities and is not included in its statutory debt calculation.
TVA is required by section 15d of the TVA Act to repay the
approximate $0.4 billion debt with interest to the United States
Treasury. TVA's outstanding debt subject to the $30 billion
statutory limit has grown steadily from $15 billion at the end of
fiscal year 1983 to $25.5 billion at the end of fiscal year 1994.
TVA's debt resulted in fiscal year 1994 total interest expense of
nearly $1.9 billion,\6 representing about 35 percent of TVA's
operating revenue. We estimate that $833 million of TVA's gross
interest expense is associated with its $14 billion investment in
nonproducing nuclear assets. Figure 2.2 breaks down TVA's
capitalization\7 and liabilities by balance sheet account.
Figure 2.2: TVA's $32 Billion
in Total Capitalization and
Liabilities as of September 30,
1994
(See figure in printed
edition.)
Source: TVA 1994 financial statements.
TVA's $30 billion statutory debt limit provided TVA with authority to
borrow billions of dollars without seeking congressional approval.
In 1979, TVA's debt ceiling was doubled from $15 billion to $30
billion. The $15 billion increase in borrowing authority greatly
exceeded what was then envisioned as being required to complete TVA's
nuclear construction program. Therefore, TVA did not have to request
any additional borrowing authority despite the operational and
construction problems associated with its nuclear program over the
last 15 years.
According to credit 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 credit rating agencies as if they have an implicit federal
guarantee. The Standard & Poor's credit rating agency's "AAA" rating
for TVA bonds is not based on a default, risk-based analysis.
Instead, the credit rating agency based its rating on the
determination that TVA's bonds have characteristics that would confer
"agency status,"\8 similar to securities issued by
government-sponsored enterprises.\9 TVA's "AAA" rating provides it
with the ability to borrow at lower interest rates and provides it
with a competitive advantage. An official from Moody's credit rating
agency confirmed that it employs substantially the same criteria as
employed by Standard & Poor's when rating TVA's bonds.
--------------------
\5 Of TVA's total debt, $3.9 billion is owed to the federal
government ($3.4 billion is owed to the Federal Financing Bank, about
$0.4 billion is appropriated debt, and about $0.1 billion is owed to
the U.S. Treasury). For purposes of comparison later in this
chapter, TVA's total debt includes $215 million in capital lease
obligations.
\6 Total interest expense equals the sum of gross interest expense
plus the interest on appropriated debt.
\7 Capitalization represents the sum of all equity accounts and
long-term debt.
\8 Standard & Poor's rating criteria attribute agency status to
securities issued by entities related to the federal government
because the securities have some of the attributes of U.S. Treasury
securities, such as being exempt from Securities and Exchange
Commission registration requirements.
\9 Government-sponsored enterprises are federally established,
privately owned corporations designed to increase the flow of credit
to specific economic sectors. Examples include the Federal National
Mortgage Association, Federal Home Loan Mortgage Corporation, and
Student Loan Marketing Association.
TVA HAS DEFERRED SIGNIFICANT
COSTS
-------------------------------------------------------- Chapter 2:1.3
TVA is excluding $14 billion in nonproducing nuclear assets from its
revenue requirements and, hence, from its rates. TVA considers these
assets to be construction in progress. As such, the costs of these
assets will not be included in rates until the units are either
completed and placed into service or cancelled. TVA charges the cost
of its PP&E and cancelled plant to ratepayers through depreciation
and amortization expense.\10 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 estimated $833
million of annual interest expense from the debt associated with
these assets is included in current rates.
Any business in a capital-intensive industry would likely have a
certain level of PP&E that is under construction and not being
depreciated. However, the size and length of TVA's deferral is
unique. On September 30, 1994, the $14 billion in nonproducing
nuclear assets accounted for about 73 percent of TVA's $19.3 billion
net nuclear PP&E. In addition, Watts Bar 1 has been under
construction for 22 years--about double the average construction
period for TVA's three operating nuclear plants. Figure 2.3 shows
the components of net nuclear PP&E for fiscal year 1994.
Figure 2.3: TVA's $19.3
Billion in Net Nuclear
Property, Plant, and Equipment
as of September 30, 1994
(See figure in printed
edition.)
Note: Assets are net of accumulated depreciation.
Source: TVA 1994 financial statements.
By the end of fiscal year 1994, TVA had depreciated $1.4 billion, or
about 7 percent, of its $20.7 billion investment in gross nuclear
PP&E. Therefore, 93 percent of TVA's gross nuclear PP&E as of
September 30, 1994, must be paid for by future ratepayers.
--------------------
\10 Depreciation is the allocation of the expense associated with
PP&E to each period benefited by the asset. Amortization is the
allocation of expenses associated with intangible and other assets,
such as abandoned plant, to each period benefitted. Both are
calculated by dividing the costs of the asset by its estimated useful
life or allowable period of time. In this report, we use
depreciation to describe allocation of costs related to PP&E, and
amortization to describe allocation of costs for all other assets.
NONPRODUCING NUCLEAR ASSETS
WILL IMPACT REVENUE
REQUIREMENTS
-------------------------------------------------------- Chapter 2:1.4
The extent of the increase in revenue requirements will depend on
when and over what period of time TVA begins recovering its nearly
$14 billion of nonproducing nuclear assets. A shorter time period
increases costs for current ratepayers while giving TVA more
flexibility in future years; in contrast, a longer period minimizes
the impact on current rates. To date, TVA has not decided the time
period for recovering the $6.2 billion invested in deferred nuclear
units. According to TVA, it is considering cancelling the deferred
units and amortizing the associated costs over 30 years. When TVA
cancelled the eight nuclear units during the 1980s, it wrote them off
over an amortization period of only 10 years. According to TVA, its
bond covenants prevent it from charging the deferred nuclear assets
against retained earnings. However, TVA has great latitude in
determining when and over what period the $6.2 billion of costs for
deferred nuclear units will be brought into revenue requirements.
If TVA is able to bring Watts Bar 1 and Browns Ferry 3 on line as
planned, the $8.5 billion of total estimated cost to complete and
restart these units would be depreciated over their estimated useful
lives. TVA has established the useful life of a nuclear reactor to
be 40 years based on its NRC operating license. Thus, Watts Bar 1
would be depreciated over 40 years. Presently, costs associated with
restarting Browns Ferry 3, which went into commercial service in
1977, would be depreciated over the 22 years remaining on its
operating license.
For illustrative purposes, we estimated the impact of including
depreciation and amortization expense for the nonproducing nuclear
assets on future revenue requirements. We used the depreciation and
amortization periods as described above. Using TVA's cost-to-
complete projections, we estimated, as shown in table 2.1, that the
nonproducing nuclear assets would increase TVA's revenue requirements
by a total of $454 million per year for at least the next 22 years.
This would result in a 9-percent increase in revenue requirements.
If the maximum amortization period for its deferred nuclear assets
was only 15 years, then TVA's annual revenue requirements would
increase by $660 million, or 12 percent.\11
Table 2.1
Estimated Annual Increase in Revenue
Requirements for Nonproducing Nuclear
Assets as of September 30, 1994
(Dollars in billions)
Total Estimated Estimated
estimated depreciation/ annual
cost to be amortization increase in
Nonproducing depreciated/ period (in revenue
nuclear assets amortized\a years) requirements
--------------- ------------- ------------- -------------
Deferred Nuclear Units
------------------------------------------------------------
Watts Bar 2
Bellefonte 1 $6.2 30 $0.207
Bellefonte 2
Construction In Progress
------------------------------------------------------------
Watts Bar 1 6.8 40 0.170
Browns Ferry 3 1.7 22 0.077
============================================================
Total $14.7 / -- $0.454
------------------------------------------------------------
\a Total estimated cost assumes TVA will (1) not spend additional
capital on Watts Bar 2 or Bellefonte 1 and 2 and (2) spend
approximately $900 million to complete Watts Bar 1 and Browns Ferry 3
in addition to the $7.6 billion already spent.
Source: GAO analysis of TVA data.
--------------------
\11 The 9-percent and 12-percent increases were calculated by
dividing our estimated $454 million and $660 million increases in
revenue requirements by TVA's 1994 total revenue requirements of $5.3
billion. These estimated annual increases do not include any
additional operating and maintenance expenses.
TVA HAS SUBSTANTIALLY HIGHER
FINANCING COSTS AND DEFERRED
ASSETS THAN NEIGHBORING
UTILITIES
---------------------------------------------------------- Chapter 2:2
To put TVA's financial condition in perspective, we compared its
financing costs and deferred assets to nine nearby IOUs. According
to industry experts, TVA's competition is most likely to come from
nearby utilities because of the cost of wheeling power. In addition,
as discussed in chapter 4, some of these utilities have submitted
bids to provide electricity to TVA's customers that are seeking power
sources other than TVA. Differences in financing structures between
TVA and IOUs make a direct comparison somewhat difficult. However,
TVA's customers are primarily concerned about electricity rates, not
financing structure. Thus comparing TVA to its neighboring IOUs is
essential. We believe the ratios we use in our comparison are
indicators of the ability of TVA to compete with neighboring IOUs.
Figure 2.4 shows a map of the service areas of TVA and neighboring
IOUs.
Figure 2.4: Map of Service
Areas of TVA and Neighboring
IOUs
(See figure in printed
edition.)
Source: Moody's 1994 Public Utilities Manual and 1993 and 1994
annual reports of the neighboring IOUs.
TVA has substantially more financing costs and deferred assets than
its neighboring utilities. In five key financial ratios we examined,
TVA's ratios, overall, indicated that it would be less competitive
than the other nine utilities. Three of these ratios are indicators
of flexibility. First, TVA's ratio of financing costs to revenue is
more than twice as high as the average for other utilities, despite
TVA's ability to borrow at lower interest rates. TVA's high
financing costs provide it with less flexibility to reduce costs and
hence lower its rates to meet price competition. Because TVA
continues to borrow and is not currently repaying any principal on
its nonappropriated debt, this ratio is not likely to decrease soon.
In addition, TVA's substantial debt subjects it to a much greater
risk of rising interest rates than its competitors. To illustrate
TVA's interest rate risk, if the interest rates at which TVA must
refinance its approximately $8.4 billion in debt maturing by 1998
increase by 1 percent, TVA's annual finance costs will increase by
about $84 million (about 1.6 percent of TVA's 1994 operating
revenue).
Second, TVA's ratio of fixed financing costs to revenue is four times
higher than the average of its neighboring IOUs. All of TVA's
financing costs are interest expense and thus are fixed. On the
other hand, IOUs common stock dividends are not contractual
obligations that have to be paid. Thus, this ratio further shows
that IOUs have more flexibility than TVA.
Third, TVA's ratio of net cash from operations\12 to expenditures for
PP&E and common stock dividends in 1994 was only 57 percent; in
contrast, the average for the nine IOUs was 95 percent. Three of the
nine IOUs had sufficient net cash provided by operations to pay for
100 percent of their PP&E expenditures and common stock dividends and
the other six IOUs had ratios ranging from 54 percent to 92 percent.
This ratio reflects TVA's inability in fiscal year 1994 to pay for
its PP&E with cash generated from operations. Unlike most of TVA's
neighboring IOUs that generated sufficient cash to pay for all or a
substantial portion of their expenditures for PP&E and common stock
dividends, TVA had to borrow to pay for about half of its
expenditures for PP&E.
The other two ratios are indicators of deferred assets. For the
first indicator, TVA's ratio of accumulated depreciation and
amortization to gross PP&E is 17 percent of its $34 billion
investment. The other utilities have ratios averaging 35 percent.
This ratio indicates that little of TVA's PP&E has been taken into
its rates via depreciation and amortization, and therefore TVA's
rates do not reflect all relevant costs. Second, TVA's deferred
assets represent 47 percent of its gross PP&E, while the ratio for
the nine IOUs averaged 3 percent. The costs that are being deferred
from current rates must be recouped either through future rates or
written off against retained earnings. Including TVA's $15.7 billion
of deferred assets (as of September 30, 1994) in future rates will
make TVA less competitive. In addition, as mentioned previously, TVA
paid nearly $833 million of interest expense in fiscal year 1994 for
these assets that do not currently benefit them.
Table 2.2, which compares these key financial ratios of TVA with the
nine neighboring IOUs, shows that TVA's high financing costs and
deferred assets will make it difficult for TVA to compete. Appendix
III describes the methodology used for computing these ratios.
Table 2.2
Comparison of Key Financial Ratios for
TVA and Neighboring IOUs, 1994
((Figures in percent))
Net cash from
Fixed operations to Accumulated
Financing financing expenditures depreciation/ Deferred
Utilit costs to costs to for PP&E and amortization assets to
y revenue revenue CSD to gross PP&E gross PP&E
------ ------------ ------------ -------------- -------------- ------------
AEP 16 8 90 38 1
CP&L 16 7 132 35 2
DR 19 9 86 34 5
DP 16 7 81 36 4
ENT 20 13 121 32 2
IL 14 11 115 31 5
KU 15 6 54 40 4
LG&E 14 6 82 35 1
SC 18 9 92 31 4
TVA 35 35 57 17 47
IOU Summary
--------------------------------------------------------------------------------
Averag 16 8 95 35 3
e
High 20 13 132 40 5
Low 14 6 54 31 1
--------------------------------------------------------------------------------
Note: CSD - common stock dividends, AEP - American Electric Power,
CP&L - Carolina Power and Light, DR - Dominion Resources, DP - Duke
Power, ENT - Entergy, IL - Illinova, KU - KU Energy, LG&E - LG&E
Energy Corp., and SC - Southern Company.
Source: GAO analysis of 1994 annual reports.
To further illustrate how difficult it will be for TVA to compete
with neighboring utilities, we compared it with American Electric
Power. American Electric has excess electricity to sell and has
already bid to supply power to two TVA-served distributors. American
Electric had about the same amount of system capacity and operating
revenues as TVA in fiscal year 1994. However, as shown in table 2.3,
at the end of fiscal year 1994, TVA had net total assets that were
more than double those of American Electric. Thus, in order to
produce approximately the same amount of power and revenues from its
operations, TVA needed twice the investment in assets as American
Electric.
Table 2.3
Fiscal Year 1994 Key Statistics for TVA
and American Electric Power
(Dollars in millions)
TVA AEP
------------------------------ ------------- -------------
System capacity (MW) 25,913\a 23,670
System sales (in millions of 122,574 116,714
kilowatt hours)
Net total assets $31,842 $15,713
Deferred assets\b $15,726 $259
Total debt $26,136 $6,309
Operating revenues $5,401 $5,505
Net financing costs $1,772 $887
Net fixed financing costs $1,772 $443
Depreciation and amortization $639 $572
expense
------------------------------------------------------------
\a Represents dependable capacity currently in service. It excludes
about 2,230 MW of capacity for Watts Bar 1 and Browns Ferry 3 that
TVA plans to bring into commercial service in 1996.
\b Deferred assets are included in net total assets. The deferred
assets include about $8 billion associated with Watts Bar 1 and
Browns Ferry 3.
Source: 1994 annual reports.
TVA's debt was four times greater than American Electric's, and TVA's
net financing costs were $1,772 million, or about double that of
American Electric's. Because TVA's financing costs are twice as high
and its net fixed financing costs are four times higher than American
Electric, it is unlikely that TVA, over the long run, can sustain
rates that are competitive with those of American Electric. TVA had
$67 million more of depreciation and amortization expense in fiscal
year 1994 than American Electric. Because TVA will ultimately have
to amortize or depreciate its nonproducing nuclear assets, its future
amortization and depreciation expense could be substantially higher
than American Electric's--possibly twice as high.
We do recognize that TVA has certain cost advantages over American
Electric. For example, TVA had lower fuel costs and does not pay
federal income tax. However, these advantages do not offset the
substantial financing costs advantage of American Electric.
--------------------
\12 Net cash from operations represents cash received primarily from
customers less cash paid for operating expenses. The cash in excess
of operations is available for expenditures for PP&E, payment of
dividends, and other investing and financing activities. Since TVA
does not issue common stock, it pays no dividends.
TVA'S AVERAGE RETAIL RATES ARE
MIXED COMPARED TO NEIGHBORING
UTILITIES BUT EXCLUDE
SUBSTANTIAL COSTS
---------------------------------------------------------- Chapter 2:3
TVA's average retail\13 electricity rates are mixed--some higher and
some lower--when compared with the rates of neighboring utilities.
However, as discussed previously, TVA's rates do not include its
nonproducing nuclear assets and thus do not reflect all relevant
costs. In the evolving competitive market, utilities with the lowest
costs and lowest rates will be at a competitive advantage.
As shown in figure 2.5, TVA's residential, commercial, and industrial
rates are low compared with the rates charged by several neighboring
utilities; however, TVA's rates are less competitive than those of
some of its neighbors. Appendix III describes the methodology used
for computing the rates in figure 2.5.
Figure 2.5: TVA's and
Neighboring Utilities' Average
Retail Residential, Commercial,
and Industrial Rates for 1993
(See figure in printed
edition.)
Source: TVA data and GAO analysis of Financial Statistics of Major
U.S. Investor-Owned Utilities 1993, Energy Information
Administration, U.S. Department of Energy, January 1995.
Including TVA's $14 billion of nonproducing nuclear assets and the
estimated $900 million to complete Watts Bar 1 and Browns Ferry 3 is
likely to increase TVA's rates and make it less competitive with
neighboring utilities. Further compounding TVA's competitive
position, FERC is projecting that electricity rates will fall.
Specifically, FERC stated that "more competition will mean lower
rates for wholesale customers and, ultimately, for consumers."\14
To analyze TVA's competitiveness with its nine neighboring utilities,
we compared the investment in PP&E per megawatt of capacity--which
depicts a utility's efficiency in building generating plants--with
the average system rates. TVA's ratio includes the estimated $900
million to complete Watts Bar 1 and Browns Ferry 3 and their expected
generating capacity. As shown in figure 2.6, KU Energy has invested
less in power plants to meet its demand and thus enjoys lower rates.
Although TVA's average system rate is currently competitive, once TVA
brings its nonproducing nuclear assets and costs to complete Watts
Bar 1 and Browns Ferry 3 into its revenue requirements, it will be
difficult for TVA to offer rates competitive with its neighbors.
Appendix III describes the methodology used for computing the average
system retail rates and ratios in figure 2.6.
Figure 2.6: Investment in PP&E
Per Megawatt of Generating
Capacity and Average System
Retail Rates for TVA and
Neighboring IOUs for Fiscal
Year 1993
(See figure in printed
edition.)
Source: GAO analysis of financial data in 1993 annual reports and
Financial Statistics of Major U.S. Investor-Owned Utilities 1993,
Energy Information Administration, U.S. Department of Energy,
January 1995.
--------------------
\13 Retail rates are the rates paid by the ultimate consumer. For
TVA, this would include the cost added by its wholesale distributors.
\14 Notice of Proposed Rulemaking and Supplemental Notice of Proposed
Rulemaking (70 FERC 61.357), FERC (Mar. 29, 1995).
CONTINUING COST OVERRUNS IN
NUCLEAR PROGRAM COULD IMPACT OTHER
POWER RESOURCES
============================================================ Chapter 3
TVA has a troubled history of building and operating nuclear plants.
As mentioned earlier, TVA has "mothballed" four nuclear units and is
continuing construction and modification at two units to bring them
into commercial operation in calendar year 1996. Watts Bar 1 has
been under construction for over 22 years and is currently estimated
to cost $6.8 billion at completion. Browns Ferry 3, shut down in
1985, is not expected to be put back into commercial operation until
1996 at a total restart cost of about $1.7 billion. Both facilities
have experienced continual delays in their scheduled completions and
resultant increases in their estimated costs to complete--called cost
overruns.
TVA also faces the need for a substantial investment in its primary
power resources--its aging coal and hydroelectric plants. TVA
expects its coal and hydroelectric system to continue to produce most
of its electricity. It anticipates spending hundreds of millions of
dollars per year for the next 26 years to upgrade these plants and
meet Clean Air Act requirements. However, further delays and cost
overruns with Watts Bar 1 and Browns Ferry 3 could limit capital
funds available for needed improvements to the coal and hydroelectric
plants.
CONSTRUCTION ACTIVITIES AT TWO
NUCLEAR UNITS CONTINUE TO
INCREASE DEBT AND DEFERRED
ASSETS
---------------------------------------------------------- Chapter 3:1
Construction activities at two nuclear units, Watts Bar 1 and Browns
Ferry 3, have involved years of schedule slips and billions of
dollars of cost overruns. Despite the problems, according to TVA's
management, these units are TVA's most cost- effective resource
options, given its short-term energy needs. According to TVA, the
high costs of stopping work while the IRP process determined future
resources precluded TVA from including these units in the process as
options.
SCHEDULE DELAYS AND COST
OVERRUNS CONTINUE AT WATTS
BAR 1
-------------------------------------------------------- Chapter 3:1.1
Although TVA certified to NRC that Watts Bar 1 qualified for an
operating license in 1985, NRC did not grant one because of
unresolved safety concerns--NRC received over 5,000 employee concerns
regarding construction deficiencies and management practices.
Between 1990 and 1993, TVA and NRC jointly agreed on 28 major
corrective programs that must be completed before Watts Bar 1 could
receive its operating license. According to TVA, one of these
corrective programs necessitated that TVA replace 457 miles of
electrical cable for the unit's safety systems at a cost of $22
million. As of March 1995, TVA had closed out 10 of the 28
corrective programs with NRC.
Table 3.1 shows the growth in total estimated cost at completion and
the slipped scheduled operation date for Watts Bar 1 over the last 5
fiscal years. Total estimated cost at completion has increased about
$1.6 billion during this period.
Table 3.1
Watts Bar 1 Estimated Costs and
Scheduled Operation Dates as of the End
of the Last 5 Fiscal Years
(Dollars in millions)
1990 1991 1992 1993 1994
--------------- ------- ------- ------- ------- -------
Balance sheet $4,773 $5,151 $5,553 $6,035 $6,445
investment at
year-end
TVA estimated 476 805 479 516 355
cost to
complete
TVA total $5,249 $5,956 $6,032 $6,551 $6,800
estimated
cost
Scheduled March March June Jan. Feb.
commercial 1992 1994 1994 1995 1996\a
operation date
------------------------------------------------------------
\a This date was established in June 1995.
Source: GAO analysis of TVA data.
At an October 1994 meeting with NRC, TVA's management disclosed
numerous construction problems, first identified in the mid-1980s,
that TVA had been unable to correct to NRC's specifications.
According to TVA's management, these problems should have been
corrected years ago. However, due to poor quality controls, TVA has
not been able to show that the deficiencies were corrected. In some
instances, TVA had certified to NRC that safety issues were "closed"
when, according to NRC, they were still unresolved. At the meeting,
NRC officials stated that the problems at Watts Bar 1 were the result
of TVA's inability to manage the project and TVA's lack of quality
assurance and oversight. In a December 1994 memorandum, NRC's
Regional Administrator overseeing Watts Bar 1 stated, "These
deficiencies have raised concerns about TVA's ability to correct
problems that must be resolved before Watts Bar can be licensed to
operate."
Subsequently, in June 1995, NRC informed us that it had seen
improvement in TVA's performance at Watts Bar 1. The Regional
Administrator stated that "problems continue to be identified by both
NRC and TVA, but NRC issues have become more isolated in nature, and
TVA has become more proactive in addressing both TVA and NRC issues."
He said that a Fall 1995 fuel load date was achievable, "assuming no
new and significant issues emerge."
During fiscal year 1994, TVA spent an average of about $1.1 million
per day at Watts Bar 1. In February 1995, TVA's estimated commercial
operation date for Watts Bar 1 slipped again, from October 1995 to
December 1995, and then in June 1995 the date slipped again to
February 1996. On the basis of TVA's fiscal year 1993 and 1994
expenditures, we estimate that the 4-month slip at Watts Bar 1 will
cost TVA about $130 million.
RESTART OF BROWNS FERRY 3
HAS BEEN SLOW AND COSTLY
-------------------------------------------------------- Chapter 3:1.2
According to TVA, bringing Browns Ferry 3, which was shut down in
1985, back into commercial operation is not expected to occur until
1996 at a total estimated restart cost of about $1.7 billion. Browns
Ferry 3 went into commercial service in 1977. Between 1980 and 1984,
it received NRC's lowest ratings for quality assurance and plant
operations. After repeated safety and regulatory concerns, in 1985,
TVA shut down Browns Ferry 3 along with its other four licensed
nuclear units (Sequoyah 1 and 2 and Browns Ferry 1 and 2). Prior to
the shutdown, Browns Ferry 3 operated an average of 60 percent of the
time while on-line.
Table 3.2 shows growth in total estimated cost at completion and the
slipped scheduled operation date for Browns Ferry 3 over the last 5
fiscal years. Total estimated cost at completion has increased about
$1.2 billion during this period.
Table 3.2
Browns Ferry 3 Estimated Costs and
Scheduled Operation Dates as of the End
of the Last 5 Fiscal Years
(Dollars in millions)
1990 1991 1992 1993 1994
--------------- ------- ------- ------- ------- -------
Balance sheet $296 $406 $775 $1,171 $1,475\
investment at a
year-end\
TVA estimated 510 610 318 780 524
cost to
complete
TVA total $806 $1,016 $1,093 $1,951 $1,999
estimated
cost
Scheduled Jan. Sept. March Dec. Feb.
commercial 1993 1993 1994 1995 1996
operation date
------------------------------------------------------------
\a Approximately $296 million of Browns Ferry 3's costs are included
in completed plant and are being depreciated and included in current
rates. As a result, at the end of fiscal year 1994, TVA's estimated
cost to restart Browns Ferry 3 was about $1.7 billion.
Source: GAO analysis of TVA data.
After TVA shut down all of its operating nuclear units in 1985, it
concentrated on restarting the two Sequoyah units first. TVA did not
begin its efforts to restart Browns Ferry 3 until January 1991.
Management at Browns Ferry stated that prior to August 1993, TVA's
start-up schedules and completion costs for restarting Browns Ferry 3
were overly optimistic. As of December 1994, TVA officials reported
that current expenditures at Browns Ferry 3 were still in line with
its August 1993 estimate, and that the unit's construction activities
had remained on schedule for over a year.
TVA is planning to reload fuel at Browns Ferry 3 in October 1995, and
plans to have the unit in full commercial operation by February 1996.
NRC stated that approval of Browns Ferry 3 for restart should go
smoothly because the unit shares many systems with Browns Ferry 2,
whose systems were inspected and approved by NRC between 1989 and
1991, when it became operational. During fiscal year 1994, TVA spent
an average of $833,000 per day at Browns Ferry 3.
COST OF COMPLETING NUCLEAR
UNITS MAY BE HIGHER THAN TVA
ANTICIPATED
-------------------------------------------------------- Chapter 3:1.3
TVA's incremental "to go" costs of completing its two nuclear units
under construction may be understated. As shown previously, TVA has
experienced problems building and operating nuclear power plants.
However, during its IRP, TVA stated that continued investment in
Watts Bar 1 and Browns Ferry 3 was economically justified because (1)
TVA needed the power soon and (2) these two nuclear units were TVA's
most cost-effective options for meeting expected growth in demand for
power.
According to its forecast, TVA needs to bring Watts Bar 1 and Browns
Ferry 3 into operation by the beginning of 1996 to have sufficient
capacity\1 to meet peak demand. TVA's load forecasting methodology
is discussed in appendix II. After establishing its need for power,
in February 1994, TVA's calculated the economic cost of meeting
future demand with these two units. Excluding its sunk cost, TVA
calculated the incremental costs of completing Watts Bar 1 and Browns
Ferry 3 and compared these costs with other alternative resource
options. TVA's analysis projected that Watts Bar 1 and Browns Ferry
3 would generate power at a first year incremental cost of 2.1 and
2.8 cents per kilowatt hour (kwh), respectively. According to TVA,
alternative resource options such as demand side management were in
the range of 3.5 cents per kwh.
If TVA's historical cost overruns and operating problems continue for
either of these two units, the actual "to go" cost will be greater
than planned. Cost overruns for these plants increase deferred
assets, debt, and financing costs, and will ultimately put upward
pressure on rates. To demonstrate, we analyzed TVA's incremental
cost calculation for Watts Bar 1. We have illustrated, by using two
scenarios, how the two most significant assumptions, cost-to-complete
and capacity factor,\2 affect the incremental cost calculation.
Table 3.3 shows the results of this analysis. Our two scenarios, a
discussion of which follows, yielded incremental cost estimates of
2.8 and 5.6 cents per kwh, in contrast with TVA's estimate of 2.1
cents per kwh.
Table 3.3
Estimate of First Year Incremental Cost
Analysis For Watts Bar 1
TVA
estimate Scenario Scenario
Major assumptions\a Feb.1994 1 2
------------------------------ -------- -------- --------
Estimated cost-to-complete\b $515 $765 $1,165
(millions of dollars)
Capacity factor 76 66 38
(percentage)
First year incremental cost 2.1 2.8 5.6
(cents per kwh)
------------------------------------------------------------
\a For all assumptions other than estimated cost-to-complete and
capacity factor, we used TVA's estimates. These assumptions include
estimates for inflation, interest rates, discount rates,
decommissioning, nuclear fuel cost, nuclear fuel escalation rate,
capital improvement and additions, and operations and maintenance
cost.
\b Cost-to-complete represents estimated costs incurred from
September 30, 1993, to completion.
Source: GAO analysis of TVA data.
Our analysis was based on assumptions that were different than TVA's
for estimated cost-to-complete and capacity factor. For scenario 1,
our analysis used TVA's actual expenditures for fiscal year 1994 of
$410 million, and added TVA's cost-to- complete estimate of $355
million as of September 30, 1994. For scenario 2, we assumed
start-up of Watts Bar 1 would be delayed by 1 year, which would not
be inconsistent with the unit's history. We assumed a delay cost of
$1.1 million per day, which is approximately what TVA spent per day
on the unit in fiscal year 1994. Such a schedule slip could add
approximately $400 million to the cost-to-complete estimate. The
scenario 1 analysis used a capacity factor of 66 percent because
TVA's three nuclear units currently in operation (Sequoyah 1,
Sequoyah 2, and Browns Ferry 2) have a combined average capacity
factor of 66 percent since their restarts in 1989, 1988, and 1991,
respectively, as shown in figure 3.1.
Figure 3.1: TVA's Three
Operating Nuclear Units'
Average Capacity Factor Since
Restart, as of September 30,
1994
(See figure in printed
edition.)
Source: GAO analysis of TVA data.
In the scenario 2 analysis, we decreased TVA's anticipated capacity
factor for Watts Bar 1 from 76 percent to 38 percent. Our analysis
of TVA's nuclear generating capacity, as illustrated in figure 3.2,
shows that TVA's five licensed nuclear units have operated at a
combined average capacity factor of 38 percent since their original
start-up.
Figure 3.2: TVA's Five
Licensed Nuclear Units' Average
Capacity Factor Since Original
Start-Up
(See figure in printed
edition.)
Source: GAO analysis of TVA data.
--------------------
\1 Capacity is the amount of electric power that can be delivered by
a generating unit at one time. TVA's current system capacity is
approximately 26,000 MW, and Watts Bar 1 and Browns Ferry 3 together
will bring an additional 2,230 MW of capacity to the system.
\2 Capacity factor is the actual gross power generation of a unit
divided by the maximum potential power generation for a given period
of time. The resulting figure indicates the percentage of time a
unit is available.
COST FOR NUCLEAR CONSTRUCTION
COULD AFFECT COAL AND
HYDROELECTRIC PROGRAM
IMPROVEMENTS
---------------------------------------------------------- Chapter 3:2
The outcome of TVA's nuclear program could limit capital funds
available for needed improvements to its coal and hydroelectric
plants. TVA is dependent on its coal and hydroelectric generating
plants, and since the early 1980s, has generated the vast bulk of its
power from these sources. Yet, while relying more on hydroelectric
and coal-fired sources of power, TVA decreased its capital
expenditures for these plants during the 1980s in anticipation of
nuclear generation coming on-line. Despite having made significant
improvements recently to its coal and hydroelectric units, TVA
anticipates needing between $240 million and $301 million per year in
constant 1994 dollars for these plants over the next 26 years. In
addition, TVA estimates that it will need substantial capital to meet
the requirements of the Clean Air Act.
SYSTEM GENERATION DEPENDENT
UPON COAL AND HYDROELECTRIC
UNITS
-------------------------------------------------------- Chapter 3:2.1
TVA's system of hydroelectric dams and coal-fired plants generated
almost 86 percent of TVA's total 1994 electricity. Figure 3.3 shows
that for the 15-year period from 1980 to 1994, the plants supplied an
average of 86 percent of TVA's electric power, ranging from a low of
75 percent in 1982 and 1983 to a high of 100 percent in 1986 and 1987
when TVA's nuclear units were shut down.
Figure 3.3: TVA Power
Generation by Fuel Source,
Fiscal Years 1980-1994
(See figure in printed
edition.)
Source: TVA data.
REDUCED CAPITAL EXPENDITURES
FOR COAL AND HYDROELECTRIC
GENERATION DURING 1980S
-------------------------------------------------------- Chapter 3:2.2
In the 1960s and 1970s, TVA and many other utilities shared the
belief that nuclear power could supplement or even replace much of
their power from coal plants. During the 1980s, TVA, like some other
utilities, decreased expenditures for capital improvements in its
coal and hydroelectric plants in anticipation of its nuclear units
coming on line. For example, TVA's expenditures for capital
improvements to its coal plants declined from $522 million in 1980 to
$118 million in 1987 (expressed in constant 1994 dollars). Capital
expenditures for the hydroelectric plants were also uneven during the
1980s. By the mid-1980s, performance of these plants had severely
deteriorated. The age\3 and reduced capital expenditures at TVA's
coal and hydroelectric plants began to affect performance. The
frequency of unplanned unit outages was high, the availability of
units to produce power was low, and, according to TVA, the cost of
operating and maintaining these units had reached historically high
levels.
--------------------
\3 The average age of TVA's coal and hydroelectric units as of
December 1994 was 37 years and 49 years, respectively.
CAPITAL IMPROVEMENT PROGRAM
INITIATED AND EXPENDITURES
INCREASED
-------------------------------------------------------- Chapter 3:2.3
Recognizing the need to improve the performance and reduce the
operating costs of its aging power-producing facilities, TVA in 1991
initiated a modernization program for the coal and hydroelectric
plants and increased expenditures for capital improvements for them.
Figure 3.4 shows TVA's capital expenditures for coal and
hydroelectric plants for fiscal years 1980 through 1994.
Figure 3.4: TVA's Capital
Expenditures for Coal and
Hydroelectric Generation in
Constant 1994 Dollars, Fiscal
Years 1980-1994
(See figure in printed
edition.)
Source: TVA data.
Since 1991, TVA data show an improvement in the performance of the
coal and hydroelectric system. According to TVA, the availability of
coal and hydroelectric units to produce power has improved,
unexpected forced outages have declined, and the cost of producing
power has decreased.
Despite recent expenditures and improvements, TVA anticipates that it
will still need large amounts of capital to continue to improve and
upgrade its coal and hydroelectric plants. TVA has projected these
costs from 1995 to 2020. These projections show that annually TVA
will need an average of $211 million to $266 million in constant 1994
dollars for capital expenditures for the coal plants and $29 million
to $35 million in constant 1994 dollars for capital expenditures for
the hydroelectric plants. Over the next 26 years, TVA expects to
spend between $5.5 billion and $6.9 billion on coal plant upgrades
and from $748 million to $914 million on hydroelectric plant upgrades
(expressed in constant 1994 dollars).
CLEAN AIR ACT REQUIRES
SIGNIFICANT CAPITAL
EXPENDITURES FOR COAL PLANTS
-------------------------------------------------------- Chapter 3:2.4
The Congress passed legislation in 1990 under title IV of the Clean
Air Act Amendments to mitigate adverse impacts of acid rain by
reducing emissions of sulfur dioxide and nitrous oxides. The
amendments will have a significant impact on TVA's coal operations,
because TVA is one of the largest coal-burning electric utilities in
the country and has one of the largest emissions reduction
obligations. The amendments will require substantial expenditures to
reduce emissions at several of TVA's coal-fired generating plants.
Specific reductions in emissions are required in two phases. Phase 1
compliance was to be implemented by January 1, 1995, and Phase 2 by
January 1, 2000. TVA has stated that Phase 1 requirements have been
met. TVA's compliance strategy for Phase 2 is a component of its IRP
decision-making process.
According to data TVA prepared for its IRP, compliance with the Clean
Air Act Amendments is estimated to cost from $1.1 billion to $1.6
billion for fiscal years 1995 to 2015 (expressed in constant 1994
dollars). According to TVA, because not all regulations have been
issued, these estimates may not reflect the actual cost of
compliance. These costs are in addition to the previously discussed
estimates.
TVA IS PROTECTED FROM COMPETITION
IN THE SHORT TERM
============================================================ Chapter 4
The wholesale electricity market is becoming increasingly
competitive. Like other utilities, TVA has taken some steps to
remain competitive. However, in the short run, several factors
protect TVA from direct competition. For example, TVA has been
granted special protections from the competitive market by the Energy
Policy Act. Furthermore, TVA's power supply contracts with its
distributors require the distributors to give TVA 10 years advance
notice before cancelling the contracts. Despite these short-term
protections, some of TVA's customers are concerned about the
possibility of future TVA rate increases and are actively seeking
alternative sources from which to buy less expensive power in the
future.
OTHER UTILITIES ARE CHANGING TO
MEET NEW COMPETITIVE PRESSURES
---------------------------------------------------------- Chapter 4:1
Since enactment of the Energy Policy Act of 1992, electric utilities
have taken steps to become more competitive. According to 1994
studies of utility business practices\1 and utilities we contacted, a
primary action utilities have taken or expect to take is to satisfy
demand by buying power or adding small gas-fired units. Other
actions include (1) downsizing staff and restructuring, including
merging with other utilities, (2) actively competing on a price basis
with other utilities to serve municipal or industrial wholesale
customers, and (3) quickly absorbing into the rates or writing off
costs associated with uneconomical plants.
Recognizing that demand levels may be uncertain in a competitive
market, many utilities are beginning to acquire new kinds of power
resources. Some utilities will not commit financial resources to
satisfy demand levels projected any further than 5 to 10 years in the
future. Many utilities plan to build less in-house capacity and rely
more on power purchased from other utilities or IPPs. When adding
capacity is necessary, utilities are planning to build smaller units,
frequently gas-fired combustion turbines, that are less capital
intensive and more flexible resources for satisfying changing demand.
These types of units allow utilities to build in relatively small MW
increments (for example, 50 MW to 150 MW), at perhaps one-quarter of
the cost of larger power plants.
As figure 4.1 shows, the nine IOUs that serve areas near TVA plan to
satisfy about 54 percent of additional demand through the year 2003
by building gas-fired plants.
Figure 4.1: Plans of TVA's
Neighboring IOUs to Satisfy
Additional Demand Through 2003
(See figure in printed
edition.)
Note: The chart excludes planned capacity purchases and demand-side
management savings for specific subsidiaries of the Southern Company
and planned capacity purchases for Duke Power.
Source: DOE and utilities' IRPs.
We discussed the evolving competitive market with utilities and
utility holding companies that sell electricity near TVA's service
area. These entities repeated some of the findings of the surveys
mentioned above. For example, according to Virginia Power officials,
the utility has taken actions to improve its competitiveness. After
cancelling four of its originally planned eight nuclear units,
Virginia Power began writing off $500 million in related costs over
15 years. Virginia Power does not plan to build new nuclear units,
although it may seek ways of extending the lives of existing units.
According to data filed with the Department of Energy (DOE), Virginia
Power through the year 2003 plans to meet up to 65 percent of its
additional demand by purchasing energy and capacity, completing two
coal-fired baseload units (constituting about 18 percent of expected
demand), and implementing demand-side management programs (reducing
expected demand by up to 16 percent).
According to company officials, Kentucky Utilities has acquired
flexible, low-cost resources; purchased power instead of building
baseload units; and trained its workforce to perform several
different types of duties, instead of specializing in only one type
of task.\2 The utility's existing capacity does not include nuclear
assets and is primarily coal-fired (82 percent), with reliance on
purchased power (14 percent). According to data filed with DOE,
through the year 2003 almost all of Kentucky Utilities' additional
requirements will be satisfied by building gas-fired plants of 110 MW
to 220 MW. Kentucky Utilities does not plan to build nuclear units.
Officials of American Electric Power, a holding company with about
24,000 MW of capacity that serves areas north of TVA's service area,
affirmed that the regional market is becoming increasingly
competitive. American Electric maintains low fixed expenses through
such actions as quickly writing off expenses associated with
cancelled nuclear units and financing its PP&E with cash flow from
operations. Although its existing capacity is primarily coal fired
(86 percent), with smaller amounts of nuclear (8 percent) and hydro
(3 percent), the company plans to satisfy almost all of its
additional capacity requirements through the year 2003 by building
gas-fired plants, according to DOE.
--------------------
\1 1994 Electric Utility Outlook, Washington International Energy
Group, Washington, D.C., Jan. 1994; and Issues and Trends Briefing
Paper: 18 Key Trends Affecting the Electric Utility Industry, Edison
Electric Institute, Washington, D.C., May 1994.
\2 Kentucky Utilities provides the lowest electricity rates of any of
TVA's neighboring IOUs. It has a capacity of about 3,700 MW.
TVA HAS TAKEN SOME ACTIONS TO
ENHANCE ITS COMPETITIVENESS
---------------------------------------------------------- Chapter 4:2
TVA has taken a number of actions in an attempt to maintain
competitive rates. TVA estimates that, since 1988, its savings from
all cost reduction and efficiency measures total more than $800
million a year. According to TVA, it reduced the size of its
workforce by over 50 percent--from about 34,000 in 1988 to about
16,500 in 1995--achieving payroll reductions of about $400 million.
TVA also decreased its fuel and purchase power costs through measures
that reduced the forced outage rates at power plants ($100 million
savings). The remaining cost reductions resulted from debt
refinancing during the 1989 to 1994 period ($300 million). Since
1986, TVA's total operating expenses have remained relatively flat.
At the end of fiscal year 1994, TVA offered its employees early
retirement and financial incentives to leave. TVA stated that this
was necessary to reduce operating expenses in order to avoid a rate
increase or layoffs in fiscal year 1996.
Despite TVA's debt increasing substantially from 1988 to 1994, TVA's
refinancing efforts have allowed it to keep its total interest
expense fairly level, as shown in figure 4.2.
Figure 4.2: TVA's Total
Interest Expense, Fiscal Years
1988-1994
(See figure in printed
edition.)
Note: Total interest expense equals the sum of gross interest
expense plus the interest on appropriated debt.
Source: TVA's 1988-1994 financial statements.
According to TVA, since 1989 it has refinanced approximately $20
billion in outstanding debt and reduced its average interest rate on
outstanding debt from 10.1 percent to 7.3 percent. A majority of the
high interest debt that TVA refinanced was owed to the Federal
Financing Bank (FFB). As of September 30, 1994, FFB held $3.4
billion of TVA's outstanding long-term debt. See appendix V for more
details on TVA's refinancing of FFB debt.
In December 1994, TVA's Chairman announced that the agency planned to
place an internal cap on its debt below the $30 billion limit set by
the Congress. The announcement came as a result of a study by TVA's
Chief Financial Officer concluding that TVA could limit its level of
debt from $27 billion to $28 billion by the end of fiscal year 1997.
This conclusion assumed TVA would build no power plants, other than
Watts Bar 1 and Browns Ferry 3, unless reductions of equal magnitude
were taken in other capital programs. Consistent with this policy,
TVA also announced in December 1994 that it would not, by itself,
complete the deferred nuclear units at Bellefonte and Watts Bar 2.
TVA plans to maintain these units until completion of its Integrated
Resource Plan in late 1995. At that time it will consider such
alternatives as (1) converting the units to another technology such
as natural gas, (2) replacing them with different types of supply-
and demand-side resource options, (3) completing the construction of
one or more of them as nuclear units in partnership with others, or
(4) maintaining them in a mothballed status pending a later decision.
As of the end of fiscal year 1994, TVA had invested $6.2 billion in
these units and estimated that the cost to complete them could be as
much as $8.8 billion more. TVA plans to complete Watts Bar 1 and
Browns Ferry 3 and bring the units into commercial service in
February 1996.
In August 1994, TVA solicited bids to purchase up to 2,000 MW of
additional baseload resources and up to 2,000 MW of additional
peaking resources; in December 1994, TVA announced it had received
bids totaling 21,800 MW. Also, in February 1995, TVA's Chairman
stated that in recognition of evolving competitive markets,
legislative provisions that prevent TVA from transmitting and
marketing its power outside of its established service area should be
eliminated, so that TVA can compete on an equal footing with its
neighbors.\3 The Chairman added that the "fence" should come down,
"unleashing the agency's potential as a nationally competitive
electric utility."
As part of the Chairman's February 1995 announcement, he also stated
that TVA had commissioned a study to examine all aspects of removing
the fence before seeking necessary legislation. The study's report,
released in April 1995,\4 recognized that TVA faces radically
different conditions today because of the realities of the rapidly
changing electric industry. The report included the following
findings.
The electric utility industry is becoming increasingly competitive
and, like other utilities, TVA is making the tough choices to
implement a vision and strategy to successfully compete.
Specifically, the Board has suspended construction on three
nuclear units and completed a 50 percent reduction in its
workforce. In addition, the Board has taken steps to control
the size and costs of TVA's capital base, including limiting
TVA's debt and suspending construction projects. These steps,
by 1997, are said to enable TVA both to continue to service its
debt and to internally generate the funds necessary for ongoing
capital additions to the system. TVA's financial condition is
sufficiently flexible and strong for entry into and success in a
competitive market--but only if it has the freedom to compete
effectively.
Nationally, electric utilities are implementing market priced
wholesale power transactions, open access transmission,
diversifying into independent power at home and abroad, and
actively pursuing the convergence of energy and communications.
TVA is largely prevented from participation in these
developments.
So that TVA can evolve as a fully competitive enterprise and assure
its current wholesale power customers a wide range of choices in
the future--including supplies from other power generators--the
Board is recommended to undertake a two-phase effort to remove
the "fence" and related restrictions. Phase 1 would allow TVA
to conduct all conventional types of wholesale business with
utilities bordering TVA and beyond. During Phase 1, TVA would
not be allowed unbalanced access to traditional nonprofit
wholesale customers of neighboring utilities, with which TVA's
relationship has been severely restricted since 1959 and which
cannot serve in the TVA territory under the TVA Act. Phase 2
would remove the "fence" entirely, giving TVA's current
wholesale customers free market access and at the same time
permitting TVA to seek markets outside the Valley on the same
basis that competitors could enter the Valley to provide
service.
TVA's transition to a fully competitive posture is not hindered by
an inherent inability to compete on a vigorous and equal basis
with others. Instead, the barriers to TVA's competitiveness are
largely found in ties to the past and the limitations imposed by
unusual and unique provisions in federal law.
TVA's power program is self-supporting and largely free of federal
financial support.
We agree that electricity markets are rapidly changing and TVA will
have to compete with other utilities; however, we disagree that TVA's
recent actions have positioned it to meet the competitive challenges
that lie ahead. Certainly, some of TVA's announced intentions are
steps in the right direction. However, the planned actions do not
significantly diminish TVA's major problems of paying down its $26
billion of debt, paying financing costs of about $1.9 billion per
year, and including in its electricity rates $14 billion of deferred
costs for nonproducing nuclear assets.
The Palmer Bellevue study does not recommend immediately opening the
market to full competition. The study recommends that TVA be allowed
to sell to customers outside its current service area for an
unspecified period while continuing the restrictions that make it
difficult for competitors to enter TVA's market. An important issue
to consider in analyzing the study's recommendation is the equity of
a proposal that solely benefits TVA to the potential detriment of
TVA's competitors.
We also believe that other issues will affect TVA's competitiveness.
For example, TVA's high debt and resultant financing costs severely
limit its ability to cut rates in response to competitive pressures
or to invest in new technologies that may decrease its costs of
generating electricity. Under one scenario, in a competitive market,
if TVA charges rates above the market-based rates of other utilities,
TVA's distributors could give notice and leave the TVA system at the
end of 10 years (or sooner if contracts can be renegotiated) to buy
power from cheaper sources. That would leave a dwindling number of
TVA distributors and customers to pay off the substantial debt that
TVA has accumulated from previous years. Under another scenario, TVA
could try to compete by selling power at market rates, even if they
were below TVA's generating and financing costs. However, in our
view, TVA could maintain these rates for only a limited time.
TVA's power program is required to be self-financing; nevertheless we
disagree that the program's finances are primarily separate from the
federal government. The government has a great financial interest in
ensuring that TVA is a going concern and that its debt becomes
manageable, because $4.2 billion of TVA's debt is owed directly to
the government. In addition, the remaining $22 billion of debt,
primarily in the form of publicly held bonds, is perceived by the
financial community as having an implicit federal guarantee.
--------------------
\3 The Chairman's announcement, however, did not indicate that TVA
wished to remove statutory provisions in the Energy Policy Act of
1992 which generally prohibit other utilities from transmitting power
over TVA's transmission network and selling the power to TVA's
customers.
\4 The Ties That Bind: TVA in a Competitive Electric Market, Palmer
Bellevue, a division of Coopers & Lybrand L.L.P., April 1995.
IN THE SHORT RUN, SEVERAL
FACTORS MAY PROTECT TVA FROM
COMPETITION
---------------------------------------------------------- Chapter 4:3
Despite TVA's large outstanding debt and problems with its nuclear
program, several factors may allow TVA to remain financially viable
over the next decade. First, TVA is currently protected from
competition by special provisions in the Energy Policy Act, as well
as by the stringent cancellation requirements in its power contracts.
Second, the departure of some of TVA's industrial load in the 1980s
left behind a remaining customer base that is much less responsive to
rate increases, because it is less able than industry to take
advantage of alternative and cheaper sources of power. And third, in
the short run, because of tight capacity margins or transmission
costs, some low-cost competitors may not be able to sell power to TVA
distributors.
STATUTORY AND CONTRACTUAL
PROVISIONS MAY MINIMIZE THE
IMPACT OF COMPETITION ON TVA
-------------------------------------------------------- Chapter 4:3.1
In the short run, TVA is shielded from competition by statutory and
contractual provisions. In 1959, the Congress amended the TVA Act to
freeze TVA's service area as it existed in 1957. This restricted
TVA's ability to compete with neighboring utilities. Conversely, in
the Energy Policy Act of 1992, the Congress safeguarded the integrity
of TVA's service area from lower cost producers in the Southeast by
restricting their sales to TVA's distributors. FERC cannot compel
TVA to provide transmission services to another utility if the
electricity to be transmitted will be consumed within TVA's service
area, with the exception of Bristol, Virginia.
TVA's wholesale power supply contracts also restrict the ability of
TVA distributors to buy electricity from other utilities. According
to TVA contracting officials and TVA distributors, until the late
1980s, TVA distributors signed contracts which required them to
satisfy all of their power needs by buying from TVA. These contracts
contained 20-year terms, but after 6 years of service had elapsed,
distributors could cancel them by giving TVA 4-years advance notice.
However, in 1989, after the city of Memphis began seeking other
sources of power, TVA revised its contracts with distributors to
increase the cancellation notice period from 4 years to 10 years.
Specifically, the new contracts automatically renew each year and
require TVA's distributors to give 10 years advance notice before
cancelling TVA's services. The contracts continue to require that
distributors satisfy all of their power requirements by buying from
TVA. According to the Tennessee Valley Public Power Association
(TVPPA), which represents most of TVA's distributors, and individual
TVA distributors that we contacted, these terms severely limit a
distributor's options to buy from cheaper sources. If a distributor
chooses to break its contract, it is subject to monetary penalties
specified in the contract. TVA officials said, however, that no
distributor has broken its contract.
Utilities that are low cost and able to deliver power to the TVA
service area may be frustrated, at least in the short run, by TVA's
contractual and statutory protections. American Electric officials
stated that its subsidiaries are low-cost producers who are willing
and able to supply TVA's larger distributors with power. American
Electric has power to sell to TVA's largest distributors and
industrial customers; its all-time peak demand, said company
officials, equals about 19,000 MW of a total capacity of about 24,000
MW. However, TVA's statutory and contractual provisions prevent
American Electric from selling power to almost all of TVA's
distributors.
REDUCTIONS IN TVA'S
INDUSTRIAL CUSTOMERS
RESULTED IN A MORE STABLE
LOAD
-------------------------------------------------------- Chapter 4:3.2
TVA has a relatively stable load consisting primarily of residential
and commercial customers. According to representatives from TVA,
distributors, and industry, the presence of a large industrial load
within a service area indicates a large amount of potential change in
a utility's load. Because electricity rates are a significant cost
for many industrial customers, the larger industrial entities are
willing and able to leave a utility's service area to find
alternative, cheaper sources of power. According to officials of the
Electricity Consumers Resource Council (referred to as ELCON),\5 the
cost of electricity for such industries as aluminum smelters, glass,
chemicals, and chlor-alkali, can equal from about 30 percent to 40
percent of production costs.
According to representatives of TVA's directly served and
distributor-served industrial customers,\6 TVA's industrial rates
were increasing at double-digit rates each year in the 1970s. For
example, according to these officials, TVA's industrial rates
increased by 22 percent in 1971, 38 percent in 1975, and 46 percent
in 1976. According to their analysis, TVA's basic industrial rates
went from an average 0.9 cents per kwh in 1970 to over 4.0 cents per
kwh in 1983. In response, industries closed or moved many plants.
TVA's sales to industrial customers declined from about 25 billion
kwh in 1979 to about 16 billion kwh in 1993. According to TVA
officials, because of this loss of industrial customers, TVA's load
today is more stable than it otherwise would have been. The increase
in load stability decreases the possible adverse short-term impact of
competition on TVA's electricity sales and revenues.
--------------------
\5 ELCON is the national association of large industrial customers.
They buy about 4 percent of the nation's electricity.
\6 These associations include the Tennessee Valley Industrial
Coalition (represents directly served TVA industrial customers) and
the Associated Valley Industries (represents distributor-served
industrial customers in the TVA service area).
LOW-COST COMPETITORS MAY NOT
BE ABLE TO SELL POWER TO TVA
DISTRIBUTORS
-------------------------------------------------------- Chapter 4:3.3
Some low-cost competitors may not be able to deliver power into the
TVA area at a competitive price because transmission charges levied
by intervening utilities would make the cost of the power
noncompetitive. For example, Virginia Power officials stated that
the utility's rates are competitive with TVA's rates, but the utility
is not now, nor will it be in the foreseeable future, in direct
competition with TVA. The officials said that to sell power to TVA's
distributors, Virginia Power's electricity must be transmitted
through Appalachian Power's service territory to the interchange
between Appalachian Power and TVA near Bristol, Virginia. According
to Virginia Power officials and our analysis of data they provided to
us, Appalachian Power's transmission tariff of $2 per kilowatt month
plus an energy charge of $1 per megawatt hour\7 may increase the
delivered cost of Virginia Power's electricity by about 10 percent.\8
A cost-competitive utility that may be willing to sell power to TVA's
customers may be limited by a lack of capacity. For example, a
Kentucky Utilities official stated that because Kentucky Utilities
operates under a relatively small capacity margin of 15 percent, the
company cannot serve TVA's larger customers. At the present time, it
could only serve TVA's smaller distributors (generally those with
loads of about 100 MW or less).
--------------------
\7 Transmission tariffs are approved by FERC.
\8 This analysis is based on a hypothetical arrangement to deliver
100 MW of capacity for a year, assuming a load factor of 60 percent.
The hypothetical charge for bulk power, excluding the transmission
tariff, includes a capacity component of $8.50 per kilowatt month and
an energy component of $30 per megawatt hour delivered.
TVA'S CUSTOMERS REACT TO
EVOLVING MARKETS
---------------------------------------------------------- Chapter 4:4
TVA's distributors and remaining industrial customers are concerned
about potential rate increases and are reacting cautiously. Some
distributors told us they wish to modify their contracts with TVA to
buy some or all of their power from other suppliers. Industrial
representatives said that industrial customers currently benefit from
special TVA rates, but TVA needs to reduce its rates more if it
wishes to be competitive with the low-cost providers of power in the
region.
DISTRIBUTORS' CONCERNS ABOUT
TVA'S RATES HAVE LED SOME TO
SEEK OPTIONS TO BUY POWER
FROM OTHER SOURCES
-------------------------------------------------------- Chapter 4:4.1
Concerns about TVA's rates have caused some distributors to consider
buying power from sources other than TVA. For example, in the late
1980s, the city of Memphis's Light, Gas, and Water Division explored
the possibility of buying power from sources other than TVA. Memphis
analyzed the prospects for TVA's future rates, given assumptions
about such factors as TVA's nuclear program and future electricity
load. At the optimistic end of its analysis, Memphis projected that
TVA's overall wholesale rates would decline in real terms from 4.3
cents per kwh in 1989 to 4.0 cents per kwh in 2010 (expressed in 1988
dollars). At the pessimistic end, Memphis projected that TVA's
average wholesale rates would almost double in real terms to 8.2
cents per kwh in 2010 (expressed in 1988 dollars). Memphis's
pessimistic analysis was based on assumptions that TVA's nuclear
program would continue to experience cost overruns, complications,
and delays. Ultimately, Memphis, which represents over 10 percent of
TVA's load, decided to stay in TVA's system because TVA addressed the
city's concerns. For example, TVA compensated the city for operating
its own transmission system by providing a credit.
In May 1990, the city of Bristol, Virginia, gave TVA written notice
that it intended to cancel its power contract effective June 30,
1995.\9 To keep Bristol as a customer, TVA offered Bristol an
extension on its existing contract through 1997. TVA also offered
the city special rates for industrial customers, as well as other
concessions. The city agreed to extend its existing terms, and
according to Bristol officials, several industrial customers have
recently saved over $80,000 per month because of the new industrial
rates. Once its contract with TVA expires, Bristol can purchase
power from utilities other than TVA. Bristol received an exemption
in the Energy Policy Act of 1992 that allows other utilities to
transmit their electricity to Bristol over TVA's power lines.
According to its General Manager, Bristol plans to solicit bids
during the summer of 1995 for electricity to be delivered in 1997.
The Four County Electric Power Association near Columbus,
Mississippi, notified TVA in December 1993 of its intent to cancel
its power contract. After analyzing TVA's financial statements, Four
County's Chief Executive Officer became convinced that TVA's nuclear
fixed costs are "uncompetitive." Four County officials said that
according to a study they commissioned, TVA's wholesale rates may
increase by 30 percent over a 10-year period. They said their study
analyzed TVA's current and future rates, along with the rates of such
utilities as Mississippi Power and Light, Mississippi Power, and
Alabama Power. However, because Four County is subject to the
10-year cancellation provisions in its contract with TVA, it cannot
stop buying power from TVA until 2003 without risking legal action.
Furthermore, under the Energy Policy Act of 1992, TVA cannot be
compelled by FERC to transmit through its transmission system the
electricity of another utility to Four County. Four County officials
believe that it will be able to finance the construction of power
lines into its service area, thus tying the cooperative into the
power grid of other utilities. In August 1994, Four County requested
competitive bids from other electric utilities, IPPs, and power
marketers, to provide it with 175 MW of power and received 22
proposals totaling 2,000 MW. By buying power from sources other than
TVA, Four County expects to reduce its power costs by about 25
percent.
Officials we spoke with from TVPPA said TVA's rates and service
reliability must remain competitive with the rates and services of
neighboring utilities and regional IPPs. If not, distributors may
seek alternative sources of power because they are under pressure
from their customers to charge low rates. According to TVPPA
officials, some TVA distributors believe that, because of changes
brought by the Energy Policy Act of 1992, their contracts with TVA
should be renegotiated. TVPPA and some of its members (including
some of TVA's largest distributors--Memphis, Nashville, Knoxville,
and Huntsville) favor renegotiating TVA's contracts to allow them the
option to buy from other utilities and IPPs, as well as TVA, and to
decrease the length of the 10-year cancellation notice provision.
--------------------
\9 Bristol's existing contract with TVA, signed in 1985, allows
Bristol to terminate TVA's services not earlier than 10 years after
the contract was signed with a 4-year advance notice requirement,
according to Bristol's General Manager.
TVA'S INDUSTRIAL CUSTOMERS
ARE CONCERNED, BUT PRAISE
TVA'S EFFORTS TO HOLD RATES
STEADY
-------------------------------------------------------- Chapter 4:4.2
Although officials that represent TVA's remaining industrial
customers are concerned about prospects for rate increases, they
praised TVA's steps to enhance the agency's competitiveness, such as
cutting costs and freezing electricity rates since 1988. They stated
that TVA's innovative industrial rate structures have succeeded in
keeping TVA's special industrial rates competitive with other
regional utilities. The officials credited TVA's interruptible
economy power with decreasing some of TVA's industrial rates to about
3 cents per kwh.
However, they are concerned that TVA's commitment to nuclear power
may jeopardize TVA's ability to maintain competitive industrial
rates. The officials stated that TVA's basic industrial rates need
to drop about 9 percent to match TVA's most inexpensive competitors.
Because IPPs can today locate power plants near factories and sell
power directly to those facilities, competition to provide electric
services to industrial customers has intensified. Moreover, TVA's
industrial customer power contracts that can be canceled with 2-year
to 5-year termination notices are less restrictive than distributors'
contracts.
OPTIONS FOR ADDRESSING TVA'S
PROBLEMS
============================================================ Chapter 5
We believe that the enormous size of TVA's debt and resultant
financing costs in the long term jeopardize TVA's ability to meet
competitive challenges from neighboring utilities, thus placing the
federal government at risk for some portion of TVA's debt. TVA's $26
billion in outstanding debt and $1.9 billion of annual financing
costs severely limit TVA's future financial flexibility. In
addition, TVA is burdened with $14 billion in nonproducing nuclear
facilities that have not been included in its electricity rates.
Despite a number of actions by TVA in recent years to improve its
financial position, including downsizing its workforce and
refinancing its debt at lower interest rates, further actions will be
necessary.
Resolving TVA's financial problems will be costly and require painful
decisions. In this chapter, we discuss a number of options available
to TVA and the Congress and highlight issues for consideration in
analyzing each option. There may well be other alternatives, and
resolving TVA's financial situation likely will require a combination
of actions. Our intent is not to present a particular solution to
TVA's dilemma; rather, our intent is to stimulate a dialogue among
the key decisionmakers concerning options available to protect the
government's interests and help TVA fulfill its announced intention
of becoming a competitive and financially viable utility.
TVA'S ACTIONS, PLANS, AND OTHER
OPTIONS ARE UNLIKELY TO MAKE IT
FULLY COMPETITIVE OR TO PROTECT
FEDERAL FINANCIAL INTERESTS
---------------------------------------------------------- Chapter 5:1
As illustrated in our report, we agree with TVA that it is operating
in a rapidly changing environment and that it will have to compete
like other utilities in the future. We disagree, however, that TVA's
recent actions and announced plans put it in a strong position to
meet the competitive challenges that lie ahead. In contrast, we
believe that because of TVA's substantial debt and resultant
financing costs, it is doubtful that TVA will be able to compete
successfully in the long run.
TVA's steps to reduce operating costs and interest expense, while
commendable, may be insufficient. These actions, which according to
TVA have resulted in $800 million in annual savings, have helped TVA
to keep its rates stable and remain competitive. However, because of
the size of operating cost savings already achieved, it is unclear
whether further significant reductions are available.
Likewise, TVA's plan to stop borrowing when its debt reaches $27
billion or $28 billion, while a step in the right direction, will not
resolve TVA's debt problem. To accomplish this goal, TVA will have
to substantially reduce its capital expenditures. In fiscal year
1994, TVA borrowed $900 million because its capital expenses ($2
billion) exceeded its cash flow from operations ($1.1 billion).
According to TVA's 1994 annual report, new borrowing is estimated to
be $1 billion for 1995 and $500 million for 1996. During fiscal year
1994, TVA spent approximately $2 million per day on its Watts Bar 1
and Browns Ferry 3 nuclear units, which represented approximately 40
percent of TVA's total capital expenditures. This construction
activity continues to increase TVA's debt, financing costs, and
deferred assets. Construction activity and the potential for future
operating problems at these two plants increase TVA's operating,
financial, and competitive risks. Given TVA's history of
construction cost overruns at Watts Bar 1 and Browns Ferry 3, along
with the tremendous capital requirements of its aging coal and
hydroelectric plants,\1 staying within its internal debt limit will
be difficult.
Assuming that TVA does limit its debt to the $27 billion or $28
billion level, it still faces annual financing costs of almost $2
billion. This financing cost places TVA at a competitive
disadvantage with its neighboring utilities and makes TVA highly
subject to interest rate fluctuations. In 1994 TVA's financing costs
represented 35 percent of its revenues, whereas neighboring IOUs'
financing costs averaged only 16 percent of their revenues. Further,
neighboring IOUs' fixed financing costs averaged only 8 percent
compared to 35 percent for TVA. We believe this difference in fixed
financing costs makes it doubtful that TVA can lower its rates to
match the projected decrease in industry rates.
TVA's current electricity rates do not include $14 billion of costs
for nonproducing nuclear assets, which TVA considers to be
construction in progress. Compared to other utilities, the dollar
amount and length of time of TVA's deferral are unique. In contrast,
IOUs absorb into their rates or write off in a much shorter time
frame costs associated with uneconomic plants. If TVA began to
amortize and depreciate its deferred assets according to its current
amortization/depreciation schedules, its revenue requirements would
increase by about $454 million per year for at least 22 years. If
all of these costs had been included in TVA's electricity rates in
1994 and TVA had not been able to offset the costs by reducing other
expenses, TVA's rates would have been increased by 9 percent which
would have decreased TVA's competitiveness compared to neighboring
utilities.
We believe that the $6.2 billion of costs associated with the three
mothballed nuclear units (Watts Bar 2, and Bellefonte 1 and 2) does
not represent a viable construction project because of the following
factors. First, these three units have not had significant
construction activity for nearly 7 years. Second, TVA recently
stated that it will not complete these units by itself. TVA lacks
the available capital to complete these units given its commitment to
cap its debt at $28 billion. Third, in a preliminary draft of its
IRP, TVA stated that it will continue to defer a final decision on
Bellefonte 1 and 2 for up to 2 more years, while studying an option
to convert the units to alternative fuel sources. Fourth, under all
of the strategies except one in the preliminary draft of the IRP, TVA
will defer a final decision on Watts Bar 2 until the year 2000, at
which time it will likely cancel the unit. Given these factors, in
our judgment, it is no longer reasonable for these costs to be
deferred from current revenue requirements. Generally accepted
accounting principles (GAAP) require these costs to be reclassified
from construction in progress to "regulatory assets" and amortization
begun immediately.\2
Although TVA's Board of Directors has announced plans to keep
electricity rates stable through 1997, TVA could consider a rate
increase. With the additional cash generated from operations, TVA
could reduce its borrowing or pay down its debt. Because of TVA's
management autonomy, no outside approval would be needed. If TVA
raised its electricity rates, certain issues would need to be
considered, including the impact a rate increase might have on TVA's
competitive position. In analyzing this, we found that assuming all
other factors remain constant,\3 a one-time rate increase of 10
percent could allow TVA to pay off about $5 billion of debt over 10
years. This would still leave TVA with an outstanding debt of about
$23 billion and with substantial annual financing costs. In
addition, TVA's customers could respond to a rate increase by
consuming less electricity, thereby offsetting some of the revenue
that TVA could derive from its rate increase.
A rate increase in a competitive environment also could cause many of
TVA's remaining industrial customers to shut down their plants and
move their operations or to cogenerate or buy power from other
electricity generators. In addition, TVA's distributors could react
by giving notice and leaving the TVA system after giving TVA the
required 10-year notice (or sooner if the contracts could be
renegotiated) to buy power from cheaper sources. One TVA distributor
recently solicited bids from other suppliers and told us it expects
to reduce its power costs by as much as 25 percent. If TVA's
distributors or other customers leave, a dwindling number would be
left behind to pay off the substantial debt that TVA has accumulated
from previous years. With fewer customers, there could be pressure
to further increase rates and this, in turn, could cause more
customers to seek other sources of electricity.
Oversight of TVA's management decisions, similar to that provided to
other utilities, might have resulted in different decisions than TVA
has made to date. Other than its $30 billion statutory debt ceiling,
TVA is subject to essentially no external oversight when deciding
what kinds of electricity generating facilities to build, how much
debt to incur, and what electricity rates to charge. Other utilities
are subject to the scrutiny of independent boards of directors,
public utility commissions, and the financial community. It is
doubtful that a public utility commission would have allowed TVA to
indefinitely defer from rates billions of dollars of construction
costs. Moreover, because TVA is a government corporation, the
financial community views TVA's bonds as having an implicit federal
guarantee. TVA's "AAA" bond rating and resultant easy access to
credit has relieved it from needing to exercise the same degree of
financial restraint as other utilities.
Because of TVA's high fixed costs and impending competition, we
believe the federal government may be at risk for some portion of
TVA's $26 billion debt. Of this amount, $3.9 billion is owed
directly to the government. The remaining $22 billion of debt
consists primarily of publicly held bonds.
TVA does not face a cash flow problem today only because it has
nearly $4 billion of remaining authority to borrow for its capital
needs. Also, in the short run, TVA is protected from competition by
statutory provisions and the 10-year cancellation provisions in its
power contracts with distributors. However, TVA could face cash
shortfalls in the future if its capital expenditures continue to
exceed its net cash from operations by nearly $1 billion per year.
--------------------
\1 For example, TVA anticipates spending from $240 million to $301
million per year (constant 1994 dollars) over 26 years for
improvements to its hydroelectric and coal plants.
\2 Statement of Financial Accounting Standards No. 71, Accounting
for the Effects of Certain Types of Regulation.
\3 This example assumes that TVA brings Watts Bar 1 and Browns Ferry
3 into commercial operation and freezes its debt at about $28
billion; and that items such as fuel costs remain the same and
ratepayers stay in TVA's system due to TVA's legislative and
contractual protections.
OPTIONS FOR CONGRESSIONAL
CONSIDERATION
---------------------------------------------------------- Chapter 5:2
For TVA to be competitive in the long term, we believe it needs,
among other things, to reduce its financing costs to levels that are
similar to neighboring IOUs. Since TVA's financing costs are
approximately double those of the neighboring IOUs, for TVA to have
comparable financing costs, it would have to reduce its debt by an
estimated 50 percent--$13 billion.\4 It is unlikely that TVA can do
this on its own. Some form of federal government intervention may be
required.
There are various options for the Congress to consider to reduce risk
to taxpayers as well as help prepare TVA to compete in the
electricity market. Among others, these options include allowing TVA
to try to manage its way through this situation (the "no action"
option), limiting or restructuring TVA's debt, removing statutory
barriers to competition, privatizing TVA, or increasing oversight of
TVA's activities.
--------------------
\4 This estimate is presented only for illustrative purposes. It
assumes that all of TVA's debt has the same interest rate as TVA's
current average annual rate of 7.4 percent. Thus, all reductions of
debt would have an equal impact on TVA's financing costs.
THE "NO ACTION" OPTION
-------------------------------------------------------- Chapter 5:2.1
One option available to the Congress is to allow TVA to continue
operating as it has done in the past to see if it can survive in a
competitive market. This option would allow TVA to continue to make
the decisions it deems appropriate, postponing for a few years a
decision on congressional intervention until a determination is made
as to whether TVA's actions have improved its competitive position.
Under this option, market forces could be allowed to run their
course, and if TVA could not make bond interest payments, then the
bondholders would have to absorb the losses. This alternative could
allow for restructuring of debt through agreements reached between
TVA and the bondholders. However, if such agreements could not be
reached, the financial market perceives that the federal government
would prevent any default by TVA on its bonds. It could be argued
that such a default may call into question the government's financial
backing of other federally-related organizations. For instance, the
total outstanding borrowing of government-sponsored enterprises was
about $1.5 trillion at the end of fiscal year 1994. This alternative
also raises the question of whether it would be considered equitable
to allow a default on investments by mutual funds, pension funds, and
insurance companies. These investors may have been attracted by
TVA's "AAA" bond rating, which is based on TVA's perceived
relationship with the government and not on its financial condition.
Important issues to consider under this option would be whether (1)
adequate assurances are provided that TVA will aggressively address
its serious financial problems and (2) TVA's planned reductions in
costs and capital expenditures go far enough. The potential risk
with this option is that TVA's financial condition could worsen,
increasing the risk to the federal government.
LIMITING OR RESTRUCTURING
TVA'S DEBT
-------------------------------------------------------- Chapter 5:2.2
The Congress could reduce TVA's current $30 billion statutory debt
limit or restructure TVA's debt. As mentioned in our 1983 report,\5
the current statutory debt ceiling for TVA could be reduced from $30
billion to a lesser amount. For example, it could be reduced to the
$27 billion to $28 billion self-imposed ceiling that TVA has
announced, or even to a lesser amount. Decreasing the debt ceiling
could force TVA to make difficult decisions about its capital and
operating expenses. It should also be recognized that limiting its
debt could adversely affect TVA's competitiveness by limiting its
ability to borrow money to finance needed improvements to its power
system.
TVA's debt could be restructured under several different
alternatives.
TVA's $3.9 billion debt owed to the federal government and the
interest on that debt could be forgiven. This action would
immediately reduce TVA's debt and financing costs and help it to
become more competitive. However, this action could set a
precedent which may encourage TVA to make management decisions
that could further increase its debt. In addition, taxpayers
who received no benefit from TVA operations would be asked to
pay for TVA's management decisions of the last several decades.
The government could explicitly guarantee TVA's bonds in exchange
for the bondholders accepting lower interest rates and longer
repayment periods. Under this arrangement, the bondholders
would bear some of the costs for TVA's financial problems.
The government could pay off all or some of TVA's remaining $22
billion of debt and then require TVA to repay the debt at lower
interest rates. This option would immediately reduce TVA's
financing costs and improve its financial viability and
competitiveness. However, this alternative would entail
substantial financial costs to the taxpayer.
TVA's annual borrowing/financing activities are included in the
federal deficit. To the extent that TVA's capital and operating
outlays exceed TVA's collections from power revenues, the federal
deficit is increased by that amount. Because TVA's $26 billion of
outstanding debt financed its capital outlays, the entire debt
balance has already been included in previous years' calculations of
the federal budget deficit. Restructuring TVA's debt as described
above could either reduce the federal government's interest income or
increase its interest expense. Thus, depending on the extent of
federal intervention, the annual cost to the government for
restructuring TVA's debt would be a portion of TVA's financing cost,
which in 1994 was $1.9 billion.
--------------------
\5 Triennial Assessment of the Tennessee Valley Authority--Fiscal
Years 1980-1982 (GAO/RCED-83-123, April 15, 1983).
REMOVING STATUTORY BARRIERS
TO COMPETITION
-------------------------------------------------------- Chapter 5:2.3
The statutory provisions in the Energy Policy Act of 1992 that exempt
TVA from having to wheel the power of other utilities to its
distributors could be repealed. In such an event, FERC could compel
TVA to transmit the power of such low-cost utilities as Kentucky
Utilities or American Electric Power into TVA's service area for sale
to TVA's distributors. As a matter of reciprocity, TVA could also be
allowed to sell its power to the customers of other utilities.
Although TVA's distributors would still be required by TVA's
contracts to buy power from TVA for some period of time, distributors
that gave cancellation notices would be able to buy power from other
sources 10 years after giving the notice. Under this scenario, all
of TVA's distributors would have a choice of utilities from which to
buy power, thus introducing full competition at the wholesale level
to the TVA service area.
Removing the "fence" and other restrictions and exposing TVA to
competition would be consistent with competitive and less regulated
markets. TVA would have to operate with increased discipline in
response to competition and other market forces. However, it could
be argued that TVA would enjoy some advantages not available to IOUs
because TVA pays no federal taxes and has access to low-cost
financing because of its status as a government corporation. Despite
these advantages, given TVA's current financial condition, TVA would
likely be unable to compete with its neighboring utilities in the
long term. If that proved to be the case, the bondholders would be
at risk of TVA's defaulting on its bonds unless the Congress
intervened.
PRIVATIZING TVA
-------------------------------------------------------- Chapter 5:2.4
Another option involves "privatizing" TVA--that is, selling TVA in
its entirety, or breaking it up and selling off individual assets.
Such a move could reduce future risk to taxpayers while subjecting
TVA fully to market conditions. However, TVA's dams and reservoirs
serve multiple purposes, such as flood control, navigation, and
recreation. These purposes would have to be considered in any
privatization effort.
Because of TVA's $26 billion debt, it is very unlikely that anyone
would want to buy TVA in its entirety. Therefore, it is more likely
that TVA's assets would be sold and the net proceeds of the sale used
to pay down all or part of TVA's debt. There may be willing buyers
for TVA's transmission system and coal and hydroelectric plants.
However, it is doubtful that anyone would buy TVA's nuclear plants,
because of their troubled history and future decommissioning costs.\6
In recent congressional testimony, the Chairman of TVA's Board
discussed the potential privatization of TVA and stated, "And so I
think you would find the situation in which some people would like to
come and buy some of the plants, take the cream and leave the skim to
the taxpayers. The taxpayers would end up, I believe, in a bailout
situation involving the nuclear program."
We did not assess the market value of TVA's assets. However, because
$14 billion of TVA's total of about $32 billion in assets are
nonproducing, it is possible that privatizing TVA and selling its
assets would not pay off all of its debt.\7 As discussed above, any
shortfall would negatively impact the federal deficit because the
interest expense associated with any remaining debt would be borne by
the federal government.
--------------------
\6 In its Integrated Resource Plan, TVA estimates that the
decommissioning costs for its nuclear power plants will range from
$200 million to $700 million each. TVA projects that the medium cost
estimate will be $300 million to $350 million per unit in 1994
dollars.
\7 Whether the proceeds from the assets sold would be sufficient to
pay off all of TVA's outstanding debt depends on numerous assumptions
and analyses that were not part of the scope of our review of TVA.
INCREASING OVERSIGHT OF TVA
ACTIVITIES
-------------------------------------------------------- Chapter 5:2.5
The management decisions that placed TVA in its current financial
condition were made without any external oversight or review.
Providing TVA with greater external oversight may help ensure that
its decisions protect the financial interests of the federal
government, ratepayers, bondholders, and other stakeholders. Also,
establishing strengthened external oversight for TVA's decision
making could provide a forum for considering a broader range of
options to resolve TVA's financial problems.
At the same time, providing oversight of TVA's management could
entail the costs and burdens associated with a new layer of
bureaucracy. Establishing a regulatory or oversight body runs
counter to the current trends in the electricity
industry--specifically, promoting competition between utilities in
wholesale transactions and prices. It should also be noted that
oversight by itself does not ensure that utilities make sound
business decisions. Many utilities that are regulated by public
utility commissions still experienced financial problems stemming
from overbuilding nuclear plants during the 1970s and 1980s.\8
Following are several oversight options.
TVA's wholesale rates could be placed under FERC's regulatory
authority. FERC already regulates the wholesale rates of IOUs,
as well as those of some publicly-owned utilities such as the
Bonneville Power Administration. However, FERC's regulation of
rates is limited to examining and approving the "reasonableness"
of the wholesale rates that a utility proposes. That might not
provide the detailed level of oversight needed to ensure that
TVA's financial and resource decisions are consistent with
paying down its debt and becoming more competitive. Providing a
more detailed level of regulatory oversight of TVA could result
in expanding FERC's mission.
A regional planning council, with representatives from key regional
and industrial stakeholders, could be established. The
Northwest Power Planning Council, for example, was created by
the Congress to emphasize local control of resource development
and power planning. The Council, with representatives from all
affected Northwestern states, develops a regional plan. All
Bonneville Power Administration proposals involving major
resources must be found consistent with the Council's plan. If
a proposal is found to be inconsistent, then Bonneville must get
specific congressional authorization for the proposal. By
establishing such a council, TVA could be made accountable to
the people of the Tennessee Valley for the actions it takes to
meet the power needs of residents and industry.
As suggested by the Southern States Energy Board, TVA's 3-member
Board of Directors could be expanded to include more members to
represent the interests of residents of the service area and
other stakeholders, such as the federal government. Unlike the
current Board, an expanded Board would not be part of the
day-to-day management of TVA's operations, thereby providing
more independent oversight. This alternative would avoid
instituting a new bureaucratic structure. At the same time,
because TVA has no stockholders who could hold an expanded Board
accountable, it is possible that over time that Board could
adopt similar policies and make the same types of decisions as
TVA's 3-member Board has done in the past.
A federal public utility commission could be established to
formally review and approve TVA's rate and resource decisions.
Again, stakeholders--such as the federal government--that are
affected by TVA's financial decisions could be represented on
this commission. Like a state public utility commission, a
federal commission would have authority to approve or disapprove
TVA's rate and resource decisions.
--------------------
\8 Electricity Supply: What Can Be Done To Revive the Nuclear
Option? (GAO/RCED-89-67, March 23, 1989).
AGENCY COMMENTS AND OUR
EVALUATION
---------------------------------------------------------- Chapter 5:3
In commenting on a draft of this report, TVA strongly disagreed with
our assessment in many areas. In addition, TVA stated that in its
opinion, the report was inaccurate in the analysis of TVA's financial
condition and made inappropriate comparisons to IOUs. TVA's comments
fell into five general areas--capital structure and debt issues,
competitiveness, deferred assets, cash flow, and options. TVA also
enclosed comments on the draft from Palmer Bellevue, an affiliate of
Coopers & Lybrand. Our response to TVA's comments related to the
five general areas and the Palmer Bellevue comments follows.
CAPITAL STRUCTURE AND DEBT
-------------------------------------------------------- Chapter 5:3.1
TVA states that we fault it for having too little equity and that we
inappropriately compared it with neighboring IOUs. TVA maintains
that its capital structure is different from that of IOUs, its
capitalization is not out of line with other utilities, and its debt
does not place taxpayers at risk or keep TVA from being competitive.
We disagree with TVA's conclusions. In chapter 2, we recognize that
TVA's only option for raising external capital is borrowing, while
IOUs also issue common and preferred stock. Our report focuses on
the financing costs resulting from each utility's capitalization
regardless of source. Our ratio of financing costs to revenue
accurately reflects the costs of debt, preferred stock, and common
stock for TVA and the IOUs. TVA's customers are not concerned about
the capital structure of TVA or neighboring IOUs; rather, they are
concerned about the rates they are charged, which are directly
affected by financing costs. TVA does not address in its comments
one of the key issues raised in our report--that TVA's financing
costs to revenue ratio is more than double (35 percent for TVA versus
16 percent for IOUs) and its fixed financing costs to revenue ratio
is more than 4 times greater (35 percent for TVA versus 8 percent for
IOUs) than the average of comparable ratios of neighboring IOUs. We
believe that the enormous financing costs resulting from TVA's $26
billion debt severely limit TVA's flexibility and makes it doubtful
that TVA can compete with neighboring IOUs in the long term, placing
the government at risk for some portion of TVA's debt.
TVA states in its comments that based on total capitalization, TVA is
not out of line with IOUs and presents a "Market Value Capitalization
Comparison" chart as of December 31, 1993, to illustrate this point.
We believe that capitalization per megawatt shown on this chart is
not relevant because it is not indicative of future revenue
requirements. In contrast, our calculation of investment in PP&E per
megawatt of generating capacity in figure 2.6 shows that TVA has the
third highest investment in PP&E per megawatt of generating capacity
among the neighboring IOUs--even assuming Watts Bar 1 and Browns
Ferry 3 come on line as planned. These investments ultimately must
be depreciated or amortized and included in revenue requirements.
Although TVA's average system rate is currently competitive, we
believe that when TVA brings its nonproducing nuclear assets into
revenue requirements, its comparatively high investment, as shown by
our calculation, is likely to adversely affect TVA's future
competitiveness.
COMPETITIVENESS
-------------------------------------------------------- Chapter 5:3.2
TVA states: "The bottom line... is that deregulation in the utility
industry is here, and that TVA, as a corporation, is ready to
compete, not retreat." TVA points to actions taken to date and future
plans to improve its competitive position. In chapter 4, we state
that these TVA actions are steps in the right direction.
Nevertheless, we do not believe that TVA's actions and future plans
significantly mitigate the competitive disadvantages created by its
substantial financing costs and deferred assets.
Our analysis of the overall competitive situation facing TVA was
echoed by Standard & Poor's, a major independent bond rating
organization in its May 1995 analysis of TVA's global power bond
issue. According to this analysis, "TVA's power program operations
are characterized by a high fixed cost burden relating to $27.1
billion of long- and short-term debt outstanding, diverse resource
mix, significant challenges remaining under its nuclear program, and
higher marginal costs of production than surrounding competitors." In
addition, Moody's, another major independent bond rating
organization, stated in its analysis of the same power bond issue
that without TVA's status as a U.S. agency, "It is highly unlikely,
however, that TVA would retain its Aaa bond rating because of, among
other things, nuclear risk and an average competitive position."
As further evidence of its competitiveness, TVA cites a study it
commissioned, The Ties That Bind: TVA in a Competitive Electric
Market (referred to as the Palmer Bellevue study), that concludes
that TVA is ready for competition. However, as discussed in chapter
4, the study recommends that TVA be allowed to sell to customers
outside its current service area for an unspecified period while its
potential competitors would be prevented from selling to customers
within TVA's service area. Creating this "one-way fence" may be
viewed as inequitable because neighboring utilities would not be
allowed to compete for customers in TVA's service area. It should be
noted that taking down the fence would be very complex given TVA's
current financial condition and that IOUs already believe that TVA
has unfair competitive advantages due to the implicit federal
guarantee on its debt and its exemption from federal taxes.
DEFERRED ASSETS
-------------------------------------------------------- Chapter 5:3.3
TVA states that our analysis misrepresents construction projects in
progress as $14 billion in deferred assets. As discussed in chapter
2, we grouped TVA's construction in progress units (Watts Bar 1 and
Browns Ferry 3) and deferred nuclear units (Watts Bar 2 and
Bellefonte 1
and 2) into a single category called deferred assets. This grouping
is entirely appropriate as none of these units generate electricity
or produce revenue and, therefore, are excluded from current revenue
requirements. Anywhere there was a distinction in accounting
treatment, we disaggregated these assets. Regardless of how labeled,
these $14 billion of assets, along with TVA's substantial financing
costs, will leave it with little flexibility to meet future
competition.
TVA also states that we advocate depreciating and/or amortizing
deferred assets in violation of GAAP. Throughout the report, we have
treated the nearly $8 billion of deferred assets associated with
Watts Bar 1 and Browns Ferry 3 as construction in progress that would
be depreciated beginning in 1996 when the two units are expected to
be brought into commercial operation. We disagree with TVA's
position that including amortization of the $6.2 billion of costs
associated with the 3 mothballed units in current revenue
requirements is not in accordance with GAAP. On the contrary, we
believe that these units no longer represent viable construction
projects and that deferral of these costs from current revenue
requirements is no longer reasonable. GAAP require these costs to be
reclassified from construction in progress to "regulatory assets" and
amortization begun immediately.\9
TVA disagrees that there will be pressure to increase rates as a
result of bringing Watts Bar 1 and Browns Ferry 3 into commercial
operation. Based on TVA's analysis, annual revenue will increase by
$626 million when Watts Bar 1 and Browns Ferry 3 begin operating.
TVA's projected annual revenue increase is very optimistic. TVA's
analysis assumes that all of the electricity generated by these two
units will be sold at current prices. For this to occur, the annual
demand for TVA's electricity would need to increase by more than 10
percent by the year the plants come on line. This is extremely
optimistic given that TVA's own load forecast shows that electricity
demand will grow by 2.4 percent per year through the year 2003. If
TVA's first-year demand increases by its projected 2.4 percent, then
revenue from increased sales within its service area (assuming no
rate increase) would only be about $130 million. The rest of the
electricity would either displace current capacity or be sold on the
spot market at, on average, significantly lower prices. In addition,
TVA assumes that these 2 units will generate electricity at 75
percent of capacity. TVA's 3 operating nuclear plants have operated
at 66 percent of capacity since restart.
We also found that TVA's scenario understates depreciation at Watts
Bar 1 by $43 million. TVA officials stated that its analysis
reallocated nearly $1.5 billion in costs from Watts Bar 1 to Watts
Bar 2. As discussed, TVA has deferred until at least the year 2000
decisions about canceling Watts Bar 2, and hence continues to defer
amortizing the costs associated with the unit indefinitely. As
stated earlier, we believe that the costs associated with Watts Bar 2
should no longer be deferred and should be amortized along with the
other two mothballed units, increasing current revenue requirements
by $207 million, assuming a 30-year amortization period. It should
be noted that using a 15-year amortization period, which would be
more consistent with IOUs, would increase revenue requirements by
$414 million per year.
--------------------
\9 Statement of Financial Accounting Standards No. 71, Accounting
for the Effects of Certain Types of Regulation.
CASH FLOW
-------------------------------------------------------- Chapter 5:3.4
TVA states that it generates more than enough cash to fund ongoing
operations and service its debt. The fact that TVA borrowed $900
million in 1994 and plans to borrow $1 billion in 1995 shows that it
does not currently generate sufficient cash from operations to
finance its capital expenditures.
TVA maintains that once Watts Bar 1 and Browns Ferry 3 are completed,
its need for capital will decrease significantly. We generally agree
that completion of Watts Bar 1 and Browns Ferry 3, assuming all other
factors remain constant, would reduce TVA's capital needs
significantly; however, the funding needed to continue work at these
two units continues to increase TVA's debt. Information previously
developed by TVA demonstrates this point. For example, TVA's
December 1994 Report on Controlling the TVA Debt projected that from
fiscal year 1995 through 1997, TVA's capital expenditures would
exceed net cash from operations by a total of about $1.7 billion. As
a result, TVA forecast that its outstanding debt would reach about
$27.6 billion by the end of fiscal year 1997. TVA reiterated this
point in February 1995 congressional testimony when it estimated that
its total debt would increase by $1 billion in fiscal year 1995 and
an additional $585 million in fiscal year 1996.
OPTIONS
-------------------------------------------------------- Chapter 5:3.5
TVA states that few utilities operate under as much oversight and
scrutiny as TVA, adding that the marketplace conducts the toughest
oversight possible. Moreover, TVA states that to compete effectively
in this competitive business environment, it must be free to make
sound business decisions to meet the needs of its customers.
We disagree with TVA's conclusion that it operates under intense
scrutiny and oversight. TVA can set its own rates and reach whatever
resource decisions it wants with little external scrutiny and without
approval from parties, such as state public utility commissions,
boards of municipal governments or customer-owners, independent
boards of directors, or stockholders. Furthermore, TVA faces only
limited oversight from the financial marketplace because the bond
market grants TVA's bonds the highest possible rating on the
assumption that the bonds are implicitly backed by the federal
government. This point was emphasized in May 1995 analyses by
Standard & Poor's and Moody's. According to Standard & Poor's
analysis, the "AAA" rating on TVA's debt "reflects the implicit
support of the U.S. The rating on TVA debt does not reflect TVA's
underlying business or financial condition. Implicit support is
Standard & Poor's view that the federal government will support
payment of principal and interest on certain debt issued by entities
created by Congress even though there is no legal obligation to do
so."
Resolving TVA's financial problems will be costly and require painful
decisions. The various options in our report were meant to stimulate
a dialogue among the key decisionmakers concerning options available.
We do not present a particular solution to TVA's dilemma; we
highlight issues for consideration in analyzing each option and
recognize that there may well be other alternatives.
PALMER BELLEVUE COMMENTS
-------------------------------------------------------- Chapter 5:3.6
Palmer Bellevue states that we give "short shrift" to some important
issues relating to TVA's competitive position. The Palmer Bellevue
comments relate primarily to the issues of taking down the fence and
TVA's production costs. In our response to TVA's comments on
competitiveness in this chapter, we clearly explain that what Palmer
Bellevue calls for in its study is the creation of a "one-way fence,"
followed at some future date by full competition. We believe this is
an unrealistic and very unlikely scenario.
Palmer Bellevue states that we ignore its conclusion that TVA is a
low-cost producer of electricity when compared to neighboring
utilities. Palmer Bellevue states that comparing TVA's incremental
and average cost of production to neighboring utilities shows that
TVA is in a relatively strong position. Because Palmer Bellevue's
calculation of TVA's incremental and average cost of producing
electricity excludes $1.9 billion of annual interest expense and
TVA's other fixed costs such as depreciation expense, we believe
their analysis is incomplete and presents a misleading view of TVA's
competitiveness. Interest expense alone represents over one-third of
TVA's total expenses while depreciation is over 10 percent more. In
addition, their analysis does not consider the impact of TVA's $14
billion of deferred assets on TVA's future rates and competitiveness.
We estimate that inclusion of deferred assets would increase TVA's
revenue requirements by 9 to 12 percent. Thus, Palmer Bellevue's
incremental and average production cost analysis excludes, at a
minimum, over half of TVA's 1994 revenue requirements. We believe
that the full cost of producing electricity is more relevant to a
utility's current and future competitiveness. A utility cannot sell
electricity at incremental costs (or average cost as calculated by
Palmer Bellevue) for too long and remain financially viable,
especially when it has $14 billion of deferred assets, $6.2 billion
of which no longer even represent viable construction projects.
-------------------------------------------------------- Chapter 5:3.7
In summary, we remain confident that our analysis is sound and
well-grounded, and that we carefully considered trends in the
electric utility industry through extensive interviews of key
industry representatives and consultants. Appendix III (1) details
the overall methodology we followed and (2) lists the numerous
organizations and groups we contacted. We have extensive internal
control processes to ensure the accuracy of data included in our
reports and to be confident that our conclusions are based on those
facts. As part of our methodology, we frequently retain industry or
other subject matter expertise to achieve the proper reporting
perspective and/or to validate our message. We provided copies of a
draft of this report to two external reviewers--Charles Luce and
Robert Fri. As discussed in appendix III, Mr. Luce is the retired
Chairman of the Board and CEO of Consolidated Edison of New York and
former Administrator of the Bonneville Power Administration, and Mr.
Fri is President and Senior Fellow of Resources for the Future. In
addition, both were members of the Southern States Energy Board
Advisory Committee on the Tennessee Valley Authority that issued the
1987 report TVA--A Path to Recovery. The comments received from
these reviewers were considered in drafting this report and both
concurred with our overall message and conclusions.
TVA also inappropriately concludes several times in its comments that
our report was influenced by IOUs. As shown by our methodology
described in appendix III, we contacted a much broader range of
industry trade groups/associations representing the interests of
public power, rural cooperatives, and TVA customers, as well as IOUs.
We also contacted relevant federal agencies, bond rating agencies and
financial analysts, TVA's auditor, load forecasting experts, and a
number of large and small TVA distributors. Consequently, we believe
our report provides the Congress with an independent and in-depth
analysis of TVA's financial condition and competitive prospects.
TVA'S INTEGRATED RESOURCE PLANNING
PROCESS
=========================================================== Appendix I
The purpose of this appendix is to describe TVA's Integrated Resource
Planning (IRP) process that is currently underway. The IRP is a
process that helps utilities evaluate a variety of supply and demand
resources to determine which ones can most cost effectively meet the
energy needs of their customers. Until the 1970s, the demand for
electricity was strong, and electricity prices were declining. As a
result, resource planning in the utility industry was
straightforward, consisting primarily of simple trend analyses to
forecast the future demand for electricity and plans for the addition
of large baseload power plants to meet the demand. During the 1970s
and 1980s, the oil embargo, high inflation, and stronger regulatory
requirements for nuclear power plants created higher utility costs
and forced utilities to increase electricity rates. As a result, the
growth in the demand for electricity decreased. Utilities began to
realize that because of the uncertainty of future electricity demand,
the construction of large power plants may not be the most economical
resource option available. As the future demand for electricity
became more difficult to predict, the industry began to experiment
with more sophisticated planning approaches and techniques. The IRP
process has evolved to address the uncertainty about the future
growth of electricity demand, as well as other changes in the utility
industry, such as the public's increasing concern with the
environmental effects of power generation and growing competition
from other power suppliers.
THE ENERGY POLICY ACT OF 1992
--------------------------------------------------------- Appendix I:1
The Energy Policy Act of 1992 requires TVA to conduct a least-cost
planning program\1 for new energy resources that evaluates the full
range of existing and incremental resources in order to provide
adequate and reliable service to its electric customers at the lowest
system cost.
In developing this least-cost plan, the act requires TVA to (1)
consider the factors of risk in power system operation, such as the
reliability and flexibility of power plants, (2) assess the ability
to verify energy savings achieved through energy conservation and
efficiency programs and the projected durability of such savings
measured over time, and (3) treat demand and supply resources on a
consistent and integrated basis. The act also requires TVA to (1)
provide an opportunity for its distributors to recommend resource
options for inclusion in the IRP, (2) encourage and assist
distributors in the planning and implementation of cost-effective
energy efficiency options, and (3) provide an opportunity for public
review and comments prior to the selection and addition of any major
new energy resource.
--------------------
\1 TVA uses the term Integrated Resource Planning when referring to
the least-cost planning process required by the act.
UNLIKE TVA'S PAST IRP EFFORTS,
TVA'S CURRENT IRP INCLUDES
PUBLIC PARTICIPATION
--------------------------------------------------------- Appendix I:2
TVA's past resource planning efforts were primarily internal analyses
with little, if any, participation from the general public. TVA's
resource planning consisted of an evaluation of the trade-offs
between supply-side and demand-side management options.\2
TVA periodically developed resource planning reports primarily to
provide analyses to support major resource decisions. For example,
TVA's review of its load growth and nuclear plant construction
situation in 1982 eventually led to the cancellation of certain
nuclear plants. In the 1980's, TVA began to produce long-term
resource plans that incorporated the uncertainties of future events.
TVA's last resource plan was completed in 1991.
TVA's current IRP process, which TVA calls Energy Vision 2020,
officially began in February 1994 and is scheduled to be completed in
December 1995. TVA issued a draft IRP plan in July 1995 and plans to
issue the final IRP plan in December 1995. The IRP report will
provide TVA with (1) a 25-year long-term energy strategy and (2) a
3-year to 5-year short-term action plan, which will identify the
initial actions or tasks that TVA will undertake in order to achieve
the objectives of its long-term plan. As part of the IRP process,
TVA will also prepare an Environmental Impact Statement to evaluate
the impacts of TVA's IRP resource decisions. TVA will prepare this
statement in accordance with the National Environmental Policy Act of
1969, which requires federal agencies to consider the environmental
impact of a new facility or modification of an existing facility.
TVA's stated main objective of the IRP process is to ensure that TVA
is competitive with other utilities and energy suppliers throughout
the United States in many aspects of its business. These aspects
include TVA's electricity rates, quality and value of services, power
system reliability, and economic development and environmental
efforts. TVA designed its IRP process using two interrelated
methods, the technical process and the public participation process.
--------------------
\2 Supply-side resources, according to TVA, are resources that meet
customer needs by increased production of electricity. TVA defines
demand-side management as programs that promote activities which
influence the customer's electricity use.
THE TECHNICAL PROCESS WILL
USE TEAMS
------------------------------------------------------- Appendix I:2.1
As illustrated in figure I.1, TVA divided the technical process into
11 major steps or "building blocks." For each building block, TVA
formed an interdisciplinary study team. TVA gave each team specific
objectives and required the teams to develop and analyze data for the
IRP process. The progress of the teams is reviewed as they present
their work to the TVA Forecast Review Board (consisting of the
managers of the major departments in TVA) and the Board of Directors.
The teams have also presented their work to the IRP Review Group (a
panel of about 20 members who represent TVA distributors, large
industrial customers, environmental and public advocacy groups, and
academicians). TVA created the IRP Review Group to provide input and
advice on IRP data and to propose additional issues or options for
further consideration in the IRP process.
Figure I.1: TVA's IRP Process
Building Blocks
(See figure in printed
edition.)
Source: TVA.
ISSUES AND VALUES
TRANSLATION TEAM
----------------------------------------------------- Appendix I:2.1.1
Early in the IRP process, the Issues and Values Translation team met
with representatives of industrial customers, distributor customers,
and environmental groups to obtain initial comments, issues, and
concerns relating to TVA and TVA's IRP process. In addition, the
team reviewed over 20 different IRP reports from other utilities to
ensure that TVA did not omit any important issues in its IRP process.
The team compiled a list of the initial issues and concerns from
these various sources and categorized them according to evaluation
criteria, objectives, constraints (absolute limits on criteria),
options, and uncertainties (factors beyond TVA's control). The team
then distributed these issues and concerns to the appropriate
building-block teams, which were required to address the issues and
concerns while developing the data for their building-block teams.
For example, the list of issues and concerns that relate to options
were disseminated to the Customer Service Options team and
Supply-Side Options team. Throughout the IRP process, TVA gathers
issues and concerns raised by the public and by TVA employees. The
building-block teams are to address these issues and concerns.
EVALUATION CRITERIA TEAM
----------------------------------------------------- Appendix I:2.1.2
The Evaluation Criteria team developed criteria for assessing the
individual options considered in the IRP process. The team sorted
the evaluation criteria into eight categories. TVA is using each
category to evaluate the options and strategies (combinations of
options) being considered in the IRP. The eight categories are: (1)
long-run cost/value, (2) electricity rates and competitiveness, (3)
reliability, (4) environment, (5) economic development, (6)
financial, (7) risk management, and (8) equity.\3 The team then
selected the measurement methodology for each criterion. For
example, TVA utilizes the Participant Test, Rate Impact Measure Test,
Total Resource Cost Test, and Total Value Test in its analysis of the
long-run cost and value of TVA's customer service options.\4
--------------------
\3 The environmental evaluation criteria was actually developed by
TVA's Environment team.
\4 According to TVA, the Participant Test measures the quantifiable
benefits and costs of an option from the point of view of the
participating customer. The Rate Impact Measure Test measures the
difference between the change in total revenues paid to a utility and
the change in total costs to a utility resulting from the option.
The Total Resource Costs Test measures the total net resource
expenditures of an option from the point of view of the utility and
ratepayers as a whole. The Total Value Test measures not only the
total cost of an option, but also the benefits or "value" that
participants and ratepayers receive.
LOAD FORECASTING TEAM
----------------------------------------------------- Appendix I:2.1.3
TVA's IRP Load Forecasting team predicted TVA's future demand for
power for the next 25 years. Predicting future demand is essential
to long-term resource planning, because if TVA underforecasts its
power demand, it may not possess sufficient resources to meet its
power needs. On the other hand, if TVA develops resources too far in
advance of actual demand, customers may face the risk of higher rates
to pay for unproductive power plants.
The team generated a long-term forecast for the growth in electricity
demand by predicting (1) TVA's system energy requirements (the amount
of total energy in kilowatt hours that TVA must produce each year to
satisfy its customers' needs) and (2) TVA's peak demand (the maximum
amount of power drawn from TVA's power system over a given period of
time). The team produced the TVA load forecast for the next 25 years
using econometric and end-use load forecasting models, most of which
were developed by the Electric Power Research Institute.
EXISTING CAPABILITIES
TEAM
----------------------------------------------------- Appendix I:2.1.4
Before TVA can decide how it will meet the forecast demand, it must
first assess the capabilities of its existing generating system. The
Existing Capabilities team determined that in fiscal year 1994, TVA
had approximately 25,600 megawatts (MW) of dependable generating
capacity\5 . Because of the possibility of power outages caused by
equipment failures or other unforeseen events, TVA assumes that its
power system is not 100 percent reliable. To estimate the future
availability of its power system, the Existing Capabilities team made
certain assumptions about the future reliability of TVA's existing
power generating facilities. For example, the team assumed that all
of TVA's nuclear power units will operate at an equivalent
availability of 67 percent.\6 The team also assumed that TVA's coal
units will operate at an equivalent availability of 85 percent, its
hydroelectric power plants will operate at an equivalent availability
of 93 percent, and its combustion turbines and pumped storage
facility will operate at equivalent availabilities of 95 percent and
89 percent, respectively.
Because its power system is not 100 percent reliable, TVA plans for
additional capacity to provide a reserve margin sufficient to
maintain the reliability of the power system. TVA estimates its
reserve margins based on an evaluation of the costs of maintaining a
reliable power system, the past and projected performance of the TVA
system, and a comparison of the performance of TVA's system with the
performance of other power systems. Using these data, the team
estimated that TVA must maintain an average annual capacity reserve
margin of 15 percent for the years 1995 through 1997 and 12.5 percent
for 1998 through 2020.
TVA also has industrial interruptible-power contracts, which allow it
to interrupt power to industrial customers during peak demand
periods. The team assumed that the amount of industrial load
available for interruption during peak periods will decrease from
1,765 MW to 1,023 MW between 2000 and 2020, due to the termination of
several interruptible-power contracts.
Based on these assumptions and TVA's fiscal year 1994 load forecast,
the team estimated that by fiscal year 1998, TVA will need
approximately 700 MW of additional capacity and several thousand more
MW by fiscal year 2005.
--------------------
\5 TVA defines dependable capacity as the amount of electric power
that TVA can deliver from a generating unit, as determined by the
manufacturer's nameplate ratings or by testing. For example, the
dependable capacity of a combustion turbine power plant, based on its
nameplate rating, would be stated as 225 MW.
\6 TVA defines the equivalent availability of a generating unit as
the maximum achievable capacity of the unit, expressed as a
percentage, after the consideration of forced outages, planned
outages, and deratings of the unit.
SUPPLY-SIDE OPTIONS TEAM
----------------------------------------------------- Appendix I:2.1.5
TVA defines supply-side options as actions that TVA can undertake to
increase the amount and reliability of the power available for its
customers. The Supply-Side Options team compiled a list of
supply-side options that included nuclear, coal, and natural gas
units, as well as power generated by independent power producers and
cogeneration facilities. The team concentrated on identifying new
options that had a reasonable likelihood of commercialization within
the next 10 years. Many of the options were developed from TVA's
internal research, data available at the Electric Power Research
Institute, and data provided by outside consultants and contractors.
The team compiled several pieces of data for each supply-side option,
including the type of energy the option would provide (baseload,
intermediate, or peak), operation and maintenance costs, availability
dates, capacity figures, fuel requirements, emission rates, and
decommissioning costs. Examples of supply-side options under
consideration include the cancellation, conversion, deferment, or
completion of nuclear plants; improvements to existing hydroelectric
plants; and the construction of new coal plants and combustion
turbines. The team also included options for renewable energy
sources, such as wind power or solar power.
The team is also evaluating proposals that give TVA the option to
purchase power from other utilities. In July 1994, TVA formally
solicited bids for option purchase agreements up to 2,000 MW of
peaking capacity in the 1997 to 2006 time period and beyond, and up
to 2,000 MW of baseload capacity in the 2000 to 2006 time period and
beyond. By December 1994, TVA had received 138 different proposals
from 38 power producers. The team will evaluate the proposals and
incorporate the most promising proposals in the IRP process. The
Integration team is evaluating each available supply-side and other
option to determine the ones or combinations that may best meet TVA's
future power needs.
CUSTOMER SERVICE OPTIONS
TEAM
----------------------------------------------------- Appendix I:2.1.6
TVA's Customer Service Options team has a primary goal of identifying
feasible customer service options--actions that TVA can take to
influence the nature of its customers' electric power demands. For
example, load management programs, such as a program that would
provide commercial customers with bill credits to curtail load when
notified by TVA, are customer service options designed to shift the
time of energy consumption from peak to off-peak hours. Utilizing
input from TVA customers, reviews of other utilities' IRP reports,
and assistance from outside consultants, the Customer Service Options
team developed customer service options for consideration in the IRP
process. Options under consideration by the team include demand-side
management programs, load management programs, self generation by
commercial and industrial customers, two types of rate options, and
beneficial electrification options.\7
In developing these options, the team identified a list of customer
service technologies, such as high efficiency heat pumps and compact
fluorescent lamps, that exist in today's market or are emerging
technologies in the utility industry. For each technology, the team
gathered data, including the costs to install the technology, the
costs to maintain the technology, the overall costs to the
distributor or industry, and the effects on energy consumption and
peak demand.
As the team created this list of technologies, it qualitatively
screened them to eliminate unfeasible ones. For example, a
technology may be screened out because it was not a good application
for the Tennessee Valley's climate. Also, an emerging technology may
not be considered if adequate data to assess its costs and impacts
were unavailable or could not be adequately estimated. During any
point in the IRP process, TVA may reconsider the technologies
eliminated from consideration during the preliminary screening.
The team ranked the load management and demand-side management
technologies by using the Total Resource Cost Test as a quantitative
test to determine the benefit/cost ratios for the technologies. The
beneficial electrification technologies were ranked using the Rate
Impact Measure Test to determine their effects on rates. The team
also evaluated the technologies using the Participant Test and the
Total Value Test.
The team then designed programs, such as financing plans and direct
appliance installation plans, that would incorporate the technologies
to achieve desired levels of voluntary customer participation, meet
TVA's financial and economic goals, and provide options for all
customer classes. In constructing the programs, the team examined
TVA's past and present customer service options, and the IRP reports
and the customer service programs of other utilities. The team also
studied 80 effective demand-side management programs compiled by the
IRT Results Center, an organization that reviews hundreds of
demand-side management programs and reports examples of the best
programs in the industry. The team evaluated the program designs
they developed using the Total Resource Cost Test, Rate Impact
Measure Test, and the Participant Cost Test.
The team then integrated the program designs and the technologies to
create customer service options. The team based the integration on
the characteristics of (1) the technologies under consideration, (2)
the customers that would benefit from the options, and (3) the
methods of delivering the energy services to the customer. Finally,
the team evaluated the options, using the various cost and impact
tests, to determine their estimated impact on TVA, its customers, and
the region as a whole.
--------------------
\7 Beneficial electrification options tend to increase sales of, and
demand for, electricity by promoting the new use of electricity or
the substitution of electricity for other fuels. These effects
should provide customer value, such as increased convenience, or
environmental benefits. For example, the electronic sterilization of
medical instruments is in TVA's IRP process.
ENVIRONMENT TEAM
----------------------------------------------------- Appendix I:2.1.7
The Environment team developed criteria to evaluate the environmental
impacts of the various options and combinations of options that are
under consideration in the IRP process.\8 The team linked the various
environmental issues and concerns that were identified by the public
with measurable scientific or environmental pollutants or activities.
The team then developed 15 different criteria to address these issues
and concerns. The team also determined the measurements for each of
the criteria. For example, the team is evaluating the effects of
potential resource options on human health and fish and aquatic life
by determining the level of various emissions released by the
options. These emissions and other criteria measurements will be
weighted by the Environment team to estimate each strategy's effects
on the environmental criteria. The team also used the list of
environmental concerns to develop environmental uncertainties, or
future events that are beyond TVA's control. The team is conducting
probability analyses of possible future regulations concerning
environmental issues and determining the effects on TVA's operations.
The team also assisted in the development of environmental strategies
(combinations of resource options) that will specifically address
existing or pending environmental legislation, such as the Clean Air
Act Amendments of 1990.
--------------------
\8 In conjunction with the IRP, TVA plans to issue an Environmental
Impact Statement, as required by the National Environmental Policy
Act of 1969, that will describe the environmental effects that are
regional, national, or global in scale, or which are generic, for a
range of strategies under consideration in the IRP process.
Strategies selected by TVA may result in site-specific resource
projects in future years. For such projects, the Environmental
Protection Agency suggested that TVA conduct detailed, site-specific
Environmental Impact Statements in the future that will address the
potential environmental impacts of the projects for the particular
location or area at which the option will be implemented.
RANKINGS TEAM
----------------------------------------------------- Appendix I:2.1.8
The Rankings team ranks the supply-side and customer service options
using TVA's IRP evaluation criteria. The team uses a computer
simulation model to create the rankings of the options. Typical
option rankings could be based on lowest total resource cost, least
amount of emissions released, highest power output, lowest impact on
rates, or any combination of these factors. The Strategic
Development team used the results of the rankings in developing
strategies.
STRATEGY DEVELOPMENT TEAM
----------------------------------------------------- Appendix I:2.1.9
The Strategy Development team constructed unique strategies by
combining various options developed by the Customer Service Options
and Supply-Side Options teams. Each strategy consists of options
that are categorized as supply-side, customer service, pricing/rates,
environment, and/or transmission options. By using the data provided
by the Rankings team, the Strategy Development team created several
strategies to address specific criteria, such as total cost,
emissions rates, and electricity rates; and to address specific
uncertainties, such as future load growth, natural gas prices, and
carbon dioxide regulations. For example, if the team wanted to
create a strategy that minimized costs, it would select the lowest
cost options determined by the ranking process for each of the above
strategy categories. The Strategy Development team forwarded these
strategies to the Integration team, which is evaluating the
strategies using TVA's evaluation criteria and the uncertainties
developed by the Uncertainties team.
UNCERTAINTIES TEAM
---------------------------------------------------- Appendix I:2.1.10
The Uncertainties team evaluated a list of issues and concerns that
refer to uncertain events in TVA's future that are beyond TVA's
control. These items were referred by the public and other
building-block teams. The Uncertainties team quantified each
uncertainty in order to evaluate impacts on resource decisions. The
team also developed a range of low, medium, and high levels for these
uncertainties. The team conducted sensitivity analyses to determine
the effect of changes to the uncertainty level on TVA's evaluation
criteria. For example, given the existing TVA generating system, an
increase in load growth could cause TVA's electricity rates to
increase. On the other hand, increases in nuclear fuel costs have a
minimal effect on TVA's electricity rates. As a result of these
analyses, the team identified load growth, nuclear issues (capacity
factor, operation and maintenance cost, and capital cost),
environmental issues (carbon dioxide compliance and air/water
environmental controls), natural gas prices, co-product prices, and
demand-side management effectiveness as the most sensitive
uncertainties in its IRP process.\9 The Uncertainties team provided
these uncertainties to the Integration team for the formation of
"futures" (combinations of two or more uncertainties), and for
analyses to determine the effects that changes to uncertainties have
on the strategies developed by the Strategy Development team.
--------------------
\9 Even though the team determined the environmental uncertainties
and the demand-side management program effectiveness uncertainties to
be marginally sensitive in most cases, TVA included them in the
integration process because of the interest of the Review Group
members in these two areas.
INTEGRATION TEAM
---------------------------------------------------- Appendix I:2.1.11
The Integration team analyzes the effects of the strategies on
evaluation criteria and determines the "flexibility" and "robustness"
of these strategies when the uncertainties of the future fluctuate.
TVA defines a "flexible" strategy as a strategy that can be changed
in the future to adapt to changing conditions. A "robust" strategy,
according to TVA, is a strategy that, once implemented, should
withstand shifts in long-term conditions in the utility industry.
For example, a flexible strategy may include the deferment of Watts
Bar 2 and Browns Ferry 1. This would give TVA the flexibility to
complete the plants in the future if TVA's load growth were higher
than expected, but it would also allow TVA the option of canceling
the plants in the future if TVA's predicted future load growth does
not warrant the completion of the plants. A "robust" strategy would
have effects on TVA's evaluation criteria (for example, costs,
electricity rates, and emissions rates) that do not vary
significantly with future changes in the uncertainties (for example,
changes in load growth, natural gas prices, and nuclear unit capacity
factors).
To generate this analysis, the team utilizes computer-based
simulation models and analytic software to simulate the power system
and analyze multi-attribute trade-offs. These tools help TVA to
determine the strategies that best satisfy the IRP evaluation
criteria and provide TVA with flexible and robust strategies for the
future. These models allow TVA to analyze and compare strategies
associated with particular futures\10 and determine the effects on
different evaluation criteria. As a result of these analyses,
"trade-offs" may occur. For example, one strategy may have lower
costs and emissions, but higher short-term rates. In this case, the
Integration team would attempt to improve the strategy by removing
options that cause the higher short-term rates. The team would
replace them with options that have lower short-term rates and that
would not significantly change the strategy's effects on costs and
emissions.
The team plans to complete these analyses in three phases. At the
end of January 1995, the team had completed the first phase of the
integration process by analyzing the 35 strategies developed by the
Strategy Development team. Some of TVA's key observations resulting
from this phase include: (1) supply-side and demand-side options
that have low costs also have low electricity rates in the short run
and low debt; (2) several options reduce environmental emissions but
increase long-term costs or electricity rates; (3) increased amounts
of demand-side management produce low costs and debt but increase
electricity rates in the short run; (4) the deferral of nuclear units
and formation of a partnership at Bellefonte have lower costs, lower
electricity rates in the short run, and reduced emissions; (5)
several strategies that lower costs and emissions have higher
electricity rates in the short run; and (6) the deferral of nuclear
units can provide flexibility in adjusting to uncertain nuclear
performance.
By the end of February 1995, the Integration team had compiled the
results of the second phase of the integration process. The team
eliminated many of the simpler strategies, referred to as customer
service and supply-side strategies, because the team wanted to
identify options to be included in more complex strategies. The team
also developed new strategies and revised several existing strategies
to reflect new data for certain options. The Integration team
finished the second phase of the integration process with 22
different strategies, each of which had been developed to address
certain criteria and/or uncertainties.
During the third phase of the integration process, which TVA
completed at the end of March 1995, the integration team continued to
analyze and revise its list of strategies. The team reduced the
number of strategies under consideration in the IRP by combining the
best options from existing strategies and by modifying existing
strategies to improve their effects on TVA's evaluation criteria
given different futures. These remaining strategies will be
incorporated into the IRP report submitted to TVA's Board of
Directors.
--------------------
\10 TVA refers to a strategy associated with a future as a
"scenario."
PUBLIC PARTICIPATION PROCESS
------------------------------------------------------- Appendix I:2.2
Pursuant to the public participation requirements of the Energy
Policy Act of 1992 and the National Environmental Policy Act of 1969,
TVA's Public Participation team developed a plan to involve the
public in TVA's IRP process. The team, with the help of consultants
and reviews of the public participation processes used by other
utilities, developed a four-part public participation process.
First, the team met with TVA's distributors, industrial customers,
environmental groups, and others, to identify initial issues,
concerns, and comments about TVA and the IRP process. TVA has also
collected written comments from the public during the IRP process.
Many of the concerns, such as concerns about TVA's debt, the future
impact of TVA's rates, and the environmental impact of various
generating options, have been incorporated into the IRP process as
evaluation criteria. For example, TVA consulted with Tennessee
Valley Public Power Association (TVPPA) on the various customer
service options in the IRP. TVA held two meetings with the TVPPA
Energy Services Committee, which consists of representatives from
TVA's distributor customers, to discuss the feasibility and cost of
various customer service options that are under consideration in the
IRP process.
Second, TVA interviewed approximately 100 opinion leaders in the TVA
service area to gather opinions on issues TVA is evaluating in its
IRP process. A consulting firm analyzed the results of the surveys,
and TVA is considering the opinion leaders' comments and concerns in
the IRP process.
Third, TVA held a series of open public meetings throughout the
Tennessee Valley. The meetings consisted of interactive computer
displays presenting information on TVA's operations and the IRP
process. TVA staff were available to answer questions from the
public about TVA and/or the IRP. In response to complaints from the
public that concerns were not being heard, TVA added an hour-long
discussion period in subsequent meetings to provide the public an
opportunity to voice their concerns to TVA. After the release of the
IRP draft report, TVA intends to hold another series of public
meetings to obtain the public's comments on the report.
Finally, TVA created the IRP Review Group, which meets monthly with
TVA to hear presentations by the different building-block teams and
to provide input concerning TVA's IRP assumptions and options for
consideration in the IRP. TVA also expects the Review Group to
provide their perspectives on issues facing TVA and to review TVA's
analyses and IRP results.
REVIEWS OF TVA'S IRP PROCESS
--------------------------------------------------------- Appendix I:3
In addition to the multitude of consultants that TVA has utilized in
developing and conducting its IRP process, several additional
consulting firms are reviewing TVA's IRP process. For example, in
April 1994, TVA hired the Tellus Institute of Boston,
Massachusetts--a consulting firm with expertise in the electricity
generation market--to review and assist with TVA's IRP process.
According to TVA officials, Tellus provides an independent review for
the TVA Board of Directors of the IRP's criteria, assumptions,
analyses, and building-block team presentations. Tellus also advises
TVA on improving the IRP methodology and data.
TVPPA selected a consulting firm in September 1994 to assist it in
analyzing certain aspects of TVA's operations, including TVA's
nuclear power plants and other power supply options, TVA's debt,
TVA's load forecasting, and the reliability of TVA's service. The
study will assist the distributors to plan the least-cost future
power supply that satisfies accepted standards of reliability,
safety, and environmental sensitivity. The consultant's findings
will be presented to TVPPA's members and to TVA prior to the issuance
of the final IRP report. Also, TVA has hired several consulting
firms on behalf of the IRP Review Group to review certain aspects of
the IRP. For example, TVA has entered into contracts with consulting
firms to review TVA's load forecast, nuclear power assumptions, and
the integration analyses of the IRP. In addition, individual IRP
Review Group members have hired consultants to review certain IRP
data presented to the IRP Review Group.
STATUS OF THE IRP PROCESS
--------------------------------------------------------- Appendix I:4
TVA distributed a preliminary draft of its Integrated Resource Plan
to the IRP review group on May 31, 1995. The draft report included a
25-year long-term action plan and a 3-year to 5-year short-term
action plan. The short-term plan identified possible actions or
tasks that TVA could undertake initially in order to achieve the
objectives of its long-term plan. The long-term plan consists of a
range or "portfolio" of preferred resource options identified through
analyses of strategies during the integration process.
TVA released its draft plan to the public at the end of July 1995.
TVA will schedule meetings to obtain comments from the general public
on its draft and publish its final IRP report in December 1995.
Finally, the IRP resource decisions that will determine TVA's overall
energy strategy for the next 25 years will be made by TVA's Board of
Directors in January 1996.
REVIEW OF TVA'S LOAD FORECASTING
========================================================== Appendix II
The purpose of this appendix is to review TVA's load forecasting
methodology, the economic inputs and assumptions that TVA used to
calculate these forecasts, and the accuracy of the results. We found
that TVA's current load forecasting methodology is generally
reasonable and state of the art when compared to other forecasting
tools available in the electric utility industry. In addition, TVA's
current methodology is substantially more sophisticated than
forecasting techniques TVA used in the 1970s and early 1980s. As a
result, the accuracy of TVA's load forecasts has improved. However,
because the past forecast accuracy cannot be extrapolated to the
future, we reviewed the general reasonableness of TVA's current
long-range 1995 load forecast by comparing it with forecasts made by
some neighboring utilities. We found that in comparison to the
neighboring utilities, TVA's current load growth forecast is at the
high end of the range.
TVA'S FORECASTING METHODOLOGY
IS GENERALLY REASONABLE
-------------------------------------------------------- Appendix II:1
In comparison with what is generally available in the utility
industry as well as what is actually used by other utilities we
contacted, TVA's forecasting methodology is generally reasonable.\1
The strength of TVA's methodology lies in its use of an extensive
forecasting system, including (1) state-of-the-art forecasting
models, (2) region-specific data, and (3) a probability analysis
assessing the uncertainty associated with key variables in the load
forecast.
--------------------
\1 This discussion refers to TVA's long-term forecasting methodology.
TVA also develops a short-term (1 year to 3 years) load forecast,
which is based on a less extensive modeling system.
TVA USES SEVERAL DIFFERENT
MODELS TO FORECAST LOAD
------------------------------------------------------ Appendix II:1.1
Three "end-use" and one "econometric" forecasting models form the
core of TVA's forecasting methodology.\2 TVA uses the output from
these models to calculate its long-term forecast for electricity load
demand by three customer classes--residential, commercial, and
industrial. Figure II.1 is a simplified representation of TVA's load
forecasting system.
Figure II.1: Simplified
Representation of TVA's Load
Forecasting System
(See figure in printed
edition.)
Source: GAO analysis of TVA data.
Each of the three end-use models is designed to forecast demand for a
specific customer type and end use. For example, TVA uses the
Residential End-Use Energy Planning System (REEPS) model to forecast
load in the residential sector. The model forecasts household demand
as a function of electricity required for specific residential uses
like space heating and cooking. In turn, residential demand for
electricity in the region is greatly affected by growth in such
economic factors as per capita income and population. In addition,
because the model allows consumers to choose between electric and gas
appliances, the prices of electricity and natural gas are important
inputs.
Similarly, the Commercial End-Use Energy Planning System (COMMEND)
model is used to forecast electricity load in the commercial sector.
In COMMEND, the load for various building types such as offices,
restaurants, and retail stores, is derived from energy use in
specific end-uses, such as lighting, computers, and air conditioning.
The key determinant of electricity demand in this customer class is
the amount of commercial floor space, which, in turn, is related to
such economic factors as the growth in economic activity and
employment, the price of electricity, and the intensity of
electricity use within each building type. For example, an increase
in economic activity leads to an increase in the demand for office
space (for example, square footage) as well as increase in the need
for lighting and heating/cooling.
Finally, the Industrial Energy End-Use Model (INFORM) model is used
to forecast load for TVA's industrial customers that are served
through its distributors. However, TVA has had limited success with
the INFORM model to date and has, instead, used its econometric model
to forecast the load for these customers. In addition, TVA forecasts
separately the load it expects to sell directly to several industrial
customers. This load forecast is developed using primarily
professional judgment and contractual agreements with individual
customers.
A fourth model that forms the core of TVA's forecasting system is the
Electricity Forecasting Model (EFM). TVA also uses this model to
forecast demand by residential, commercial, and industrial customers.
However, EFM forecasts are based on more aggregate data, including
such factors as the regional price of electricity and income and
employment, rather than specific end-uses.\3
As shown in figure II.1, TVA relies on several other models to derive
its load forecasts. For example, the Regional Economic Simulation
Model (RESM) is used to forecast key regional economic factors for
the TVA region, and a financial model (FINESSE) is used to develop
electricity prices which are key inputs to the load forecasting
system.
To develop the final load forecast for each customer class, TVA's
analysts use the forecasts produced by the end-use models and the
econometric models as well as professional expertise. In other
words, during a "chalkboard session," the analysts compare and
contrast the models' forecasts with their own professional judgment,
the prior year's forecast, and basic trends in electricity demand in
order to derive a forecast for each customer class. For example, the
analysts might compare the REEPS and the EFM residential forecasts
with last year's forecast and an extrapolation of recent consumption
patterns to select the most plausible forecast for this customer
class.
Finally, using the load forecasts calculated from the core
forecasting models as an input into the Hourly Energy Load Model
(HELM), TVA's analysts develop the reference load forecast for the
entire TVA system. HELM is also used to derive TVA's peak demand
forecast.
--------------------
\2 In an end-use model, demand is derived from specific end uses of
electricity (for example, cooking) and the factors that influence
such uses. The econometric approach uses past statistical
relationships between electricity sales and key variables (for
example, economic activity and price) to forecast future sales.
\3 According to TVA analysts, the combination of the end-use and
econometric forecasting models allows the analysts to take advantage
of the strengths of both approaches. For example, one of the
benefits of using the end-use models is that TVA can assess the
potential effect of future energy efficiency standards on electricity
demand. Conversely, because the econometric approach relies
primarily on historical relationships among key variables to project
load, the use of EFM's forecasts ensures that the load forecast
incorporates past customer behavior. However, neither approach can
accurately predict all future changes, such as changes in consumer
taste and technology.
TVA USES REGION-SPECIFIC
DATA IN DEVELOPING ITS
FORECASTS
------------------------------------------------------ Appendix II:1.2
We found that TVA has made a reasonable attempt to use region-
specific data to modify its models to reflect the characteristics of
TVA's power service area. Because some of TVA's forecasting models
were designed and built by industry consultants for use by utilities
nationwide, their structure and data may reflect a national average
and, as a result, can be modified to reflect the characteristics of
the region in which they are used. For example, TVA has developed
region-specific data to modify REEPS for such things as the type of
appliances used by the residential customers in its power service
area. However, neither TVA nor any other utility we contacted has
developed a complete region-specific data system.
However, among the utilities that we contacted, TVA more than other
utilities has developed its own regional modeling capability in order
to forecast economic factors for the TVA region. For example, key
regional economic variables, such as economic growth and employment,
which are used in TVA's modeling system are developed by TVA's
analysts using this regional economic forecasting model.
TVA USES PROBABILITY
ANALYSIS TO ADDRESS
UNCERTAINTY IN KEY VARIABLES
------------------------------------------------------ Appendix II:1.3
After the reference forecast is derived, TVA analysts use probability
analysis to address the uncertainty associated with a few key
variables used in its models and to develop a range of alternative
forecasts. Although TVA's uncertainty analysis is limited to a few
key variables, we found that TVA's probability analysis is generally
more extensive than that used by other utilities we contacted.
Using this uncertainty analysis, TVA's analysts can assess the impact
of a range of values for the key variables on the reference forecast.
For example, using a high and low value for regional economic growth
and the probability associated with each growth assumption, high and
low alternative load forecasts and their probabilities are
calculated. These high and low forecast alternatives include
cumulative effects of the variation of all key variables. At this
point, all alternative forecasts are ranked from high to low, and two
forecasts are selected from this range. The analysts select the two
forecasts that reflect an acceptable high and low probability. For
example, TVA's current low forecast reflects a load demand with a
cumulative probability of 10 percent; that is, TVA's analysts believe
there is only a 10-percent chance that the actual load will be lower
than this low forecast. Similarly, the high growth demand has a
90-percent cumulative probability, which means that TVA's analysts
believe there is only a 10-percent chance that the actual load will
be higher than this high forecast.
ACCURACY OF TVA'S CURRENT
LONG-TERM FORECAST IS UNCERTAIN
-------------------------------------------------------- Appendix II:2
Primarily as a result of an improvement in its load forecasting
methodology, the accuracy of TVA's medium-term load forecasts has
improved over time. However, we could not independently verify the
accuracy of TVA's long-term forecasts. Because of changes in TVA's
methodology, the record of TVA's past forecast performance cannot be
used to assess the ability of TVA's current methodology to forecast
accurately. In addition, such an assessment would require the future
values for forecast variables. On the other hand, the general
reasonableness of the current load forecast can be determined by
comparing it with forecasts made by other neighboring utilities. We
found that TVA's 1995 reference load forecast is at the high end of a
range of forecasts made by these other utilities.
IMPROVEMENT IN METHODOLOGY
HAS LED TO INCREASED
ACCURACY
------------------------------------------------------ Appendix II:2.1
TVA's load forecasting methodology progressed from a simple trend
approach in the mid-1970s to the more sophisticated methods used
today. As a result, the accuracy of TVA's medium-term (4 years to 5
years) forecasts made in the 1980s and the early 1990s improved
substantially. As shown in figure II.2, the mean absolute error\4
of TVA's medium-term load forecasts declined from 17.7 percent in the
1970s to 2.7 percent in the early 1990s.\5
Figure II.2: Accuracy of TVA's
Medium- term Historic Load
Forecasts
(See figure in printed
edition.)
Note: Mean absolute error is calculated using the average of the
4-year and 5-year forecasts for each vintage between 1970 and 1990,
and the 4-year forecast for vintage 1991. Vintage is the fiscal year
for which the forecast is prepared.
Source: GAO analysis of TVA's load forecasts.
Trend analyses, or extrapolations of past consumption patterns, were
used by TVA and other electric utilities in the 1970s to forecast
load demand. Because the early 1970s was a period of growth in
demand for energy, forecasts made using this approach in the
mid-1970s projected increasing load demand throughout the 1980s.
Partly as a result of these forecasts, TVA began an ambitious program
to build additional nuclear generating capacity. However,
electricity consumption declined in the mid-1970s following the 1973
energy crisis and declined again in the late 1970s and early 1980s as
a result of high energy prices and lower economic growth.
To improve its forecasts, TVA analysts turned to more sophisticated
modeling techniques, which enabled them to relate the load forecast
directly to the key variables that affect electricity demand, such as
growth in regional economic activity. As a result of these
improvements, TVA's load forecasts in the early 1980s were revised
downward. Based partly on these revised lower forecasts, TVA
cancelled construction on eight nuclear units.
An additional factor, according to TVA analysts, that contributed to
an improvement in the accuracy of TVA's load forecasts was an
increase in the diversity of its customer base. TVA's customer base
diversified in the 1980s as more energy-intensive firms, such as
several primary producers of aluminum, ferro-alloys, and chemicals,
terminated or scaled back production. Load demand based on a more
diversified customer base will be less susceptible to fluctuations in
demand for electricity by any one customer. Similarly, load
forecasts made by TVA in the late 1970s included load required by the
Department of Energy's (DOE) uranium enrichment facility. Because
DOE cancelled this contract, TVA's earlier forecasts overstated
actual load demand.
--------------------
\4 Mean absolute error is the mean difference, regardless of sign,
between the actual value and the forecast value, calculated using
each year of the forecast.
\5 Although there is no agreement among experts about the acceptable
level of accuracy, some utility forecasters believed that a 5
percent, plus or minus, medium term accuracy is reasonable.
TVA'S 1995 REFERENCE LOAD
FORECAST IS AT HIGH END OF
RANGE FOR NEIGHBORING
UTILITIES
------------------------------------------------------ Appendix II:2.2
We found that TVA's fiscal year 1995 reference load forecast is at
the high end of the range of available load forecasts made by TVA's
neighboring utilities and DOE's Energy Information Administration.\6
However, we could not independently assess the accuracy of TVA's 1995
forecast. As shown in figure II.3, TVA's 1995 forecast projects a
2.4 percent annual increase (compound growth) in demand for
gigawatt-hours between 1994 and 2003.
Figure II.3: Growth in
Electricity Load Forecast by
TVA, Neighboring Utilities, and
the Energy Information
Administration for 1994-2003
(See figure in printed
edition.)
Notes: The Southeastern Electricity Reliability Council's (SERC)
Southern Subregion forecast includes forecasts made by several
utilities, including those represented by the Southern Company.
Energy Information Administration's forecast is for the SERC region,
excluding Florida.
Load forecasts are based on the economic and energy-use
characteristics of a utility's service territory and may not be fully
comparable. We used 1994 as the base year for this analysis.
Source: GAO analysis of data from TVA, neighboring utilities, and
DOE.
Figure II.4 compares TVA's peak forecasts in MW with the forecasts of
other utilities.
Figure II.4: Growth in
Electricity Peak Demand
Forecast by TVA and Neighboring
Utilities for 1994-2003
(See figure in printed
edition.)
Notes: The Southeastern Electricity Reliability Council's (SERC)
Southern Subregion forecast includes forecasts made by several
utilities, including those represented by the Southern Company.
Load forecasts are based on the economic and energy-use
characteristics of a utility's service territory and may not be fully
comparable. We used 1994 as the base year for this analysis.
Source: GAO analysis of TVA's and neighboring utilities' data.
We used this comparison to assess the general reasonableness of TVA's
current load forecast because TVA's record of past performance cannot
be used to assess the accuracy of the current load forecast. That
is, due to changes in TVA's methodology over the last 20 years, TVA's
historic forecasts cannot be used to develop appropriate measures of
long-term (10 to 20 years) accuracy.
--------------------
\6 Because the load forecasts are based on different geographic areas
as well as different types of electricity consumers, they are not
entirely comparable. We make the comparison to illustrate generally
how different utilities and the Energy Information Administration
view future load demand in the southern region of the United States.
We based this comparison on the reference forecast because this
forecast has the highest probability. However, TVA's low forecast
alternative, which has a lower probability, projects lower load
growth for the same time period.
TVA'S KEY REGIONAL ECONOMIC
GROWTH ASSUMPTION IS MORE
OPTIMISTIC THAN DATA
RESOURCES, INC.'S
------------------------------------------------------ Appendix II:2.3
TVA's reference forecast is driven partly by TVA's forecast of
economic activity. We found that TVA's assumption about future
economic activity is at the high range when compared to other
available forecasts for the region. Based on RESM, its own economic
forecasting model, TVA estimates that its service area will grow at a
3.9 percent annual rate between 1993-2000, and a 2.4 percent annual
rate between 2000-2020.\7 TVA's projection of 3.9 percent annual
growth over the 1993-2000 period is based primarily on an expectation
that durable industries such as transportation will expand at a
greater rate in its service area than in the U.S. as a whole.
In comparison, growth projections made by Data Resources, Inc., (DRI)
for the East South Central Region of the United States, including
Kentucky, Alabama, Mississippi, and Tennessee, are less optimistic.\8
As shown in figure II.5, DRI projects a growth rate of 1.1 percent in
total employment over 1994- 2004 versus TVA's 1.8 percent projection
over the same period.
Figure II.5: Growth in Total
Employment Forecast by TVA and
Data Resources, Inc., for
1994-2004
(See figure in printed
edition.)
Note: TVA's employment growth forecast is for the TVA power service
area, and DRI's growth projection is for Tennessee, Kentucky,
Alabama, and Mississippi combined. We used 1994 as the base year for
this analysis.
Source: GAO's analysis of TVA and DRI data.
In addition, figure II.6 shows that both DRI and the Energy
Information Administration project a negative growth in manufacturing
employment for the region over the same period, whereas TVA projects
a slightly positive growth. Because economic growth is a key factor
in determining future load growth, a lower forecast economic growth
would result in lower load demand projections for TVA's power service
area.
Figure II.6: Growth in
Manufacturing Employment
Forecast by TVA, Data
Resources, Inc., and the Energy
Information Administration for
1994-2004
(See figure in printed
edition.)
Note: TVA's growth projection is for the TVA power service area, and
the DRI and Energy Information Administration projections are for
Tennessee, Kentucky, Alabama, and Mississippi combined. We used 1994
as the base year for this analysis.
Source: GAO's analysis of TVA, DRI, and DOE data.
--------------------
\7 Growth rates are for gross regional product for the power service
area.
\8 We used DRI's employment projections for East South Central
because comparable gross regional product data were not available
from DRI and these four states comprise an important portion of TVA's
power service area.
OTHER KEY VARIABLES THAT
AFFECT TVA'S REFERENCE
FORECAST ARE REASONABLE
------------------------------------------------------ Appendix II:2.4
According to TVA analysts, the 1995 reference load forecast is also
dependent on several other key variables, including the price of
natural gas and TVA's future competitive success. We found that
TVA's forecast of the price of natural gas is generally comparable to
projections made by DRI. However, the reasonableness of TVA's
assumption about future competitive success could not be determined.
These other key variables are discussed below.
Natural Gas Prices: TVA's reference load forecast is based in part
on an expectation that the average natural gas price will
increase by 3.8 percent annually in nominal terms between
1993-2000. This forecast is in the general range of DRI's May
1994 forecast of 4.5 percent annual growth rate.
Competition: TVA analysts recognize that the upcoming changes in
the utility industry could have a significant impact on their
competitive position and future load forecast. However, TVA's
1995 reference load forecast assumes that TVA will neither gain
nor lose customers to its competitors. Because it is unclear at
this point how competition will impact TVA and the utility
industry, we could not determine the reasonableness of TVA's
assumption.\9
In addition to the assumption regarding its competitive position, TVA
also assumed that there will be some increase in customers generating
their own electricity through cogeneration, but no increases from
other electricity suppliers, such as independent power producers.
According to TVA, its historical data show that in the TVA power
service area, few firms are willing to develop an independent
electricity plant. Assumptions made by other utilities in this area
ranged from growth to no growth in these alternative power sources.
Again, given the uncertainty associated with the direction of the
industry, we cannot determine the reasonableness of these
assumptions.
--------------------
\9 TVA is currently attempting to model in a more systematic way the
potential impact of a more competitive market. If successful, this
information will be incorporated into the fiscal year 1996 load
forecast and revised IRP.
OBJECTIVES, SCOPE, AND METHODOLOGY
========================================================= Appendix III
On March 9, 1994, a hearing on TVA was held by the Subcommittee on
Investigations and Oversight of the House Committee on Public Works
and Transportation. As a result of concerns raised during and after
this hearing, several Members of the House and Senate requested that
we examine various TVA issues. On the basis of subsequent
discussions with the requesters' offices, we agreed to examine the
implications for TVA and possibly the federal government of the
financial issues facing TVA in light of the increasingly competitive
electric utility market. More specifically, we agreed to provide our
views on the issues that can impact TVA's financial condition,
including how TVA's rates compare with those of its competitors, and
examine the status of TVA's power program. In response to other
issues raised, we also examined the status of TVA's Integrated
Resource Planning (IRP) process (app. I), reviewed TVA's past and
present load forecasting methodologies (app. II), and analyzed TVA's
use of in-substance defeasance to refinance debt (app. V).
ASSESSING ISSUES THAT CAN
IMPACT TVA'S FINANCIAL
CONDITION
----------------------------------------------------- Appendix III:0.1
In assessing the issues that can affect TVA's financial condition, we
reviewed appropriate legislation affecting TVA, such as the Tennessee
Valley Authority Act of 1933 as amended, and the applicable sections
of the Energy Policy Act of 1992. We discussed TVA's accounting
policies and practices with its Chief Financial Officer, Treasurer,
and auditor and analyzed TVA's financial statements for the past 12
years. TVA's annual financial statements are audited by Coopers &
Lybrand L.L.P. (Coopers & Lybrand), an independent public accounting
firm. These audits are conducted in accordance with private sector
and government auditing standards. On the basis of its audits,
Coopers & Lybrand issues opinions on the fairness of TVA's financial
statements and on the adequacy of TVA's internal controls and
compliance with key laws and regulations. Coopers & Lybrand issued
an unqualified opinion on TVA's 1994 financial statements, indicating
that they are fairly presented in all material respects. However, in
1994, the opinion also included a "matter of emphasis" relating to
TVA's $6.2 billion of 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 1993 audit work papers to obtain
background information. Throughout our report, where possible, we
used audited numbers from TVA's 1994 and prior years' annual reports.
To determine TVA's relative financial health, we computed and
analyzed five different financial indicators for TVA and neighboring
investor-owned utilities (IOU) for fiscal year 1994.\1
These indicators, which are expressed as ratios, were computed as
follows.
The ratio of financing costs to revenue was calculated by dividing
financing costs by operating revenue for the fiscal year. The
financing costs include interest expense on short-term and
long-term debt, appropriated investment (TVA only), and
preferred and common stock dividends (IOUs only). Note that
preferred and common stock dividends were included in the IOUs'
financing costs to reflect the difference in the capital
structure of these entities and TVA.
The ratio of fixed financing costs to revenue was calculated by
dividing financing costs less common stock dividends by
operating revenue for the fiscal year. Common stock dividends
were excluded from the IOUs' financing costs because they are
not contractual obligations that have to be paid.
The ratio of net cash from operations to expenditures for PP&E and
common stock dividends was calculated by dividing net cash from
operations by expenditures for PP&E and common stock dividends
for the fiscal year. Net cash from operations represents the
cash received from customers minus the cash paid for operating
expenses. Thus, net cash from operations represents the cash
available for expenditures for PP&E, common stock dividends
(IOUs only), and other investing and financing transactions.
Again, we included common stock dividends in the IOUs ratios to
reflect the difference in cash flow requirements for these
entities and TVA.
The ratio of accumulated depreciation and amortization to gross
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 in progress and deferred
nuclear units (TVA only). Deferred nuclear units are included
for TVA because they are treated by TVA as construction in
progress (i.e., not depreciated).
For purposes of this report, we refer to utility holding companies
and their subsidiaries as IOUs. We limited our selection to nine
IOUs 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. In addition, some of these utilities have submitted
bids to provide electricity to TVA customers who are seeking power
sources other than TVA. We did not include any publicly owned
utilities in our analysis because the publicly owned utilities that
provide electricity in the states served by our IOU comparison group
generally only distribute but do not generate electricity. The IOUs
and their subsidiary utilities used in our comparisons included: (1)
American Electric Power, Inc. (including Appalachian Power, Columbus
Southern Power, Indiana Michigan Power, Kentucky Power, Kingsport
Power, Ohio Power, and Wheeling Power), (2) Carolina Power and Light
Company, (3) Duke Power Company, (4) Dominion Resources, Inc.
(including North Carolina Power and Virginia Power), (5) Entergy
Corporation (including Arkansas Power and Light, Gulf States
Utilities, and Mississippi Power and Light), (6) Illinova Corporation
(including Illinois Power), (7) KU Energy Corporation (including
Kentucky Utilities), (8) LG&E Energy Corp. (including Louisville Gas
and Electric), and (9) The Southern Company (including Alabama Power,
Georgia Power, Gulf Power, and Mississippi Power). The financial
data used in computing the ratios were obtained from the audited
financial statements in the utilities' fiscal year 1994 annual
reports.
We reviewed the financial statements contained in the 1993 and 1994
annual reports of TVA and the IOUs. To obtain information on various
issues facing utilities, we also reviewed the management discussions
and analyses contained in TVA's 1993 and 1994 annual reports, and the
IOUs' 1993 annual reports. These issues included competition, energy
arrangements with other utilities, nuclear power issues, efforts and
costs related to meeting the Clean Air Act requirements, capital
structure, growth rates, accounting issues that could affect the
utilities' current and future financial condition, and electricity
rates. In addition, we contacted financial analysts to identify the
criteria they use to evaluate the financial condition of electric
utilities.
We discussed TVA's current financing and investment policies and
strategies with TVA's Chief Financial Officer and Treasurer. We
discussed TVA's financing policies and current borrowing options with
an official at the Federal Financing Bank (FFB). We also interviewed
government bond analysts at Moody's and Standard & Poor's--two major
bond rating organizations--to determine the factors that underlie
TVA's "AAA" bond rating. In addition, we examined TVA's in-substance
defeased debt issues (as discussed in appendix V) to determine if
this debt should apply against TVA's $30 billion borrowing limit. We
also discussed TVA's December 12, 1994, Report on Controlling the TVA
Debt (debt study) with TVA's Chief Financial Officer.
In comparing retail rates, we calculated the average system,
residential, commercial, and industrial rates for TVA's nine
neighboring IOUs by dividing the revenue from the sale of electricity
to each group by the respective total kilowatt hours sold.
Residential sales are to households, and industrial sales are to
businesses generally engaged in mining or manufacturing. Commercial
sales are to businesses not covered in the industrial category. We
recognize that most of TVA's sales are at the wholesale level.
However, to compare TVA to IOUs, we obtained TVA's retail rates from
its December 1994 Report on TVA's Nuclear Options.
To analyze the effect of TVA's nuclear construction program on TVA's
future rates, we estimated amortization and/or depreciation expense
for TVA's investment in nuclear assets over the likely amortization
and/or depreciation time periods. These investments are currently
excluded from TVA's rates.
We examined the increase in competition among electric utilities
caused by the Energy Policy Act of 1992 and TVA's prospects for
competing successfully in the evolving market. We contacted the
Edison Electric Institute, American Public Power Association, and the
National Rural Electric Cooperatives Association, as well as
individual electric utilities or utility holding companies, such as
American Electric Power, Dominion Resources, and KU Energy, and we
reviewed their financial reports and resource plans to determine (1)
past resource decisions that could enhance or decrease their
competitiveness, (2) current plans for responding to increasing
competition, and (3) relative financial well-being.
We contacted national and regional associations\2 that represent
TVA's electricity distributors and large industrial customers to
understand their concerns about TVA's future competitiveness and
future rates. For a more detailed examination of these topics, we
interviewed officials from TVA's largest distributors (representing
about 29 percent of TVA's power demand), including the municipal
utilities of Memphis, Nashville, Knoxville, and Chattanooga,
Tennessee and Huntsville, Alabama. We also interviewed officials
from the Decatur and Fort Payne, Alabama, utilities in order to gain
the perspectives of TVA's smaller municipal customers. We
interviewed officials from the municipal power agency in Bristol,
Virginia, and the Four County Electric Power Association in Columbus,
Mississippi, because these utilities, along with the Memphis utility,
have explored leaving the TVA power system to procure cheaper power
from other suppliers. In addition, we analyzed the provisions of
TVA's contracts to determine how difficult it would be for a TVA
distributor to end its contract and leave the TVA system.
--------------------
\1 The fiscal year ends for TVA on September 30 and the IOUs on
December 31.
\2 The National Rural Electric Cooperatives Association, American
Public Power Association, Tennessee Valley Public Power Association,
Electricity Consumers Resource Council, and the Tennessee Valley
Industrial Coalition.
ASSESSING THE STATUS OF
TVA'S POWER PROGRAM
----------------------------------------------------- Appendix III:0.2
In assessing 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 having the Watts Bar 1 and Browns Ferry 3 nuclear
units in operation by 1995 and 1996, respectively. We focused on
TVA's nuclear power program because it is associated with a
substantial portion of TVA's $26 billion debt, and because it has
experienced problems over the past 20 years.
We interviewed TVA's Vice President of Nuclear Operations and the
Executive Staff Support Manager for Nuclear Operations; and we
discussed the current and past construction and operational problems
of the Browns Ferry, Sequoyah, and Watts Bar nuclear units with the
Vice President of each of the nuclear plants. We discussed current
and past safety and licensing issues at TVA's nuclear plants with
various officials of the Nuclear Regulatory Commission (NRC),
including the Director for the Office of Nuclear Reactor Regulation,
the Regional Administrator for NRC Region II, the Branch Chief for
Nuclear Licensing Renewal, and the Senior Resident Inspector at the
Watts Bar Nuclear Plant. We also met with the Vice President for
Governmental Affairs at the Institute for Nuclear Power Operations.
We reviewed previous GAO, TVA, and NRC reports on TVA's nuclear power
program. We also examined TVA and NRC reports regarding allegations
of safety, engineering, operational, and managerial problems. Many
of these allegations are significant because NRC has determined that
TVA must resolve them to NRC's satisfaction before TVA can bring into
commercial operation its Watts Bar 1 and Browns Ferry 3 nuclear
units. We also reviewed NRC's most recent "Systematic Assessment of
Licensee Performance" reports for each of TVA's nuclear units,
because these reports provide information on how well nuclear plant
management is directing operations and providing needed resources to
assure plant safety.
We examined data on how much power was generated by TVA's nuclear
units from each unit's initial date of commercial operation through
the end of fiscal year 1994. We reviewed TVA documents showing the
unplanned and planned outages at each of TVA's nuclear units from
first commercial operation date through fiscal year 1994.
For TVA's Watts Bar 1 and Browns Ferry 3 nuclear units, we reviewed
TVA documents showing historic and recent construction schedule slips
and cost overruns, and cost estimates to complete these units from
1990 to 1994. We discussed TVA's decision to complete the Watts Bar
1 and Browns Ferry 3 nuclear units with TVA resource planning
officials. We also reviewed TVA's costs and assumptions included in
its incremental cost analysis for completing these units. Using
TVA's methodology, we conducted our own incremental cost analysis on
Watts Bar 1, using less optimistic assumptions than those considered
by TVA. We used our Watts Bar 1 analysis for illustrative purposes
in this report.
We also reviewed TVA's program for operating, maintaining, and
upgrading its nonnuclear power assets, primarily its hydroelectric
and coal-fired units. The hydroelectric and coal-fired units are
important because they accounted for an average of 86 percent of
TVA's electric power during fiscal years 1980 to 1994. These units
also supplied the bulk of TVA's power during 1986 and 1987 when TVA's
nuclear operations were completely shut down. During this time, TVA
relied on its nonnuclear power plants in order to satisfy almost all
of its customers' requirements.
For TVA's hydroelectric and coal-fired units, we obtained and
analyzed data from fiscal years 1980 to 1994 on annual generation;
capital expenditures; operating and maintenance expenditures; unit
availability to produce power; and planned, unplanned, and
maintenance outage rates. We also reviewed TVA's projected capital
and operating and maintenance costs through the year 2020. We
obtained data on the age of the coal-fired and hydroelectric units;
plans to upgrade or retire these units; and TVA's assessments of its
costs of complying with environmental requirements, including Clean
Air Act requirements. We discussed operations and expenditures with
various TVA officials, including the Manager of Fossil and Hydro
Generation Planning and the Manager of Financial Services.
DETERMINING THE STATUS OF
TVA'S INTEGRATED RESOURCE
PLANNING PROCESS
----------------------------------------------------- Appendix III:0.3
To examine the status of TVA's IRP process, we reviewed the
requirements for the process as established in the Energy Policy Act
of 1992. We also attended TVA's monthly IRP meetings between July
1994 and March 1995 and interviewed responsible TVA officials. We
reviewed various documents pertaining to the IRP process. These
included documents on TVA's projected need for additional power
resources, such as its December 1994 report entitled, Report on TVA's
Nuclear Options; demand- and supply-side resources proposed by TVA in
its IRP process; and planning considerations that TVA associated with
a cleaner environment. We also contacted members of TVA's "Review
Group," which is providing TVA with advice on its IRP process and
resources the IRP should consider.
We monitored the progress of outside consultant reviews of TVA's IRP
process by discussing the status of the consultants' work with TVA
officials and stakeholders, and by obtaining and examining
documentation that describes the scope and status of the consultants'
work.
We did not review the effectiveness of TVA's IRP process because it
was still subject to change during the course of our review, and the
final IRP plan was not scheduled to be completed until December 1995.
ASSESSING TVA'S PAST AND
PRESENT LOAD FORECASTING
METHODS
----------------------------------------------------- Appendix III:0.4
To gain an understanding of TVA's load forecasting process, we
examined TVA's past and present methodology for projecting
electricity load. We interviewed TVA's load forecasting officials
and reviewed energy and economic forecasting documentation that
describes TVA's forecasting methodology. To compare TVA's
forecasting models and methods against the state-of-the-art
forecasting practices within the utility industry, we interviewed
forecasting experts at the Electric Power Research Institute,
Lawrence Berkeley Laboratory, Edison Electric Institute, Energy
Information Administration, and several energy consulting firms,
including Barakat and Chamberlin, LCG Consulting, and HBRS. We also
obtained and reviewed modeling documentation provided by these
organizations.
We compared TVA's methodology with the methodologies of other
utilities by interviewing forecasting officials and reviewing
forecasting documentation at a number of utilities or utility holding
companies in the Southeast, including Dominion Resources, Kentucky
Utilities, and Duke Power. We also interviewed forecasting officials
from the Wisconsin Electric Power Company, New England Electric
Systems, Pacific Gas and Electric Company, and the California Energy
Commission.
To examine the accuracy of TVA's historic load forecasts, we compared
its annual net system requirement forecasts from 1970 to 1991 with
the actual net system requirements for the same years. We used
standard measures of accuracy, such as the mean absolute percentage
error and the root mean square error, in our evaluation of each
forecast year. To assess the relative accuracy of TVA's forecasts,
we reviewed the forecasting literature and discussed historical
forecasts with officials from other utilities, including Wisconsin
Electric Power Company, Duke Power, and Kentucky Utilities.
To examine the reasonableness of TVA's fiscal year 1995 long-term
load forecast, we compared it with the load forecasts of neighboring
utilities, including Virginia Power/North Carolina Power, Duke Power,
and Kentucky Utilities. We evaluated the reasonableness of TVA's
economic assumptions by interviewing economists at 11 different
universities in or near the TVA service area. We also compared TVA's
1994 regional economic forecast with comparable regional forecasts,
including those produced by Data Resources, Inc., and the Energy
Information Administration.
Our evaluation of TVA's forecasting system was limited to a review of
the overall integration of the load forecasting system, the general
structure of the individual forecasting models, and TVA's uncertainty
analysis. We did not evaluate TVA's calibration of equations or
models, or the specific input data used to develop the load
forecasts.
A list of the organizations and groups we contacted during the course
of our work follows. We conducted our review between June 1994 and
July 1995 in accordance with generally accepted government auditing
standards. We obtained written TVA comments on a draft of our
report, which are contained in appendix IV. We also requested and
received comments from two external reviewers--Mr. Charles Luce\3
and Mr. Robert Fri\4 --on a draft of this report. Both reviewers
concurred with the overall message and conclusions of our draft
report and offered other comments that we have incorporated in this
report, where appropriate.
--------------------
\3 Mr. Luce is the retired Chairman of the Board and CEO of
Consolidated Edison of New York and is currently a consultant for
Consolidated Edison. He is also a former Undersecretary of the U.S.
Department of the Interior and Administrator of the Bonneville Power
Administration. In addition, Mr. Luce was a member of the Southern
States Energy Board Advisory Committee on the Tennessee Valley
Authority that issued the 1987 report entitled TVA--A Path to
Recovery.
\4 Mr. Fri is President of Resources for the Future. He is also a
former Deputy and Acting Administrator for the Environmental
Protection Agency and a former Deputy and Acting Administrator for
the Energy Research and Development Administration. In addition, Mr.
Fri was a member of the Southern States Energy Board Advisory
Committee on the Tennessee Valley Authority that issued the 1987
report entitled TVA--A Path to Recovery.
ORGANIZATIONS AND GROUPS THAT
GAO CONTACTED
------------------------------------------------------- Appendix III:1
FEDERAL AGENCIES
----------------------------------------------------- Appendix III:1.1
Bonneville Power Administration
Department of Energy, including the Energy Information
Administration
Environmental Protection Agency
Federal Energy Regulatory Commission
Federal Financing Bank
Nuclear Regulatory Commission, Headquarters, Atlanta Region, TVA
Sites
BOND RATING AGENCIES AND
FINANCIAL ANALYSTS
----------------------------------------------------- Appendix III:1.2
Standard & Poor's, New York, NY
Moody's Investors Service, New York, NY
Fitch Investors Service, Inc., New York, NY
INDEPENDENT PUBLIC
ACCOUNTING FIRM
----------------------------------------------------- Appendix III:1.3
Coopers & Lybrand L.L.P.
NEIGHBORING ELECTRIC
UTILITIES OR HOLDING
COMPANIES
----------------------------------------------------- Appendix III:1.4
American Electric Power, Columbus, OH
Dominion Resources (Virginia Power/North Carolina Power), Richmond,
VA
Kentucky Utilities, Lexington, KY
LOAD FORECASTING EXPERTS,
RESOURCE PLANNING EXPERTS,
AND REGIONAL ECONOMICS
EXPERTS
----------------------------------------------------- Appendix III:1.5
Barakat and Chamberlin, Inc., Oakland, CA
California Energy Commission, Sacramento, CA
Oak Ridge National Laboratory, Oak Ridge, TN
New England Electric Systems (load forecasting unit), Westboro, MA
Duke Power Company, Charlotte, NC
Kentucky Utilities, Lexington, KY
Pacific Gas and Electric Company, San Francisco, CA
Wisconsin Electric Power Company, Milwaukee, WI
Lawrence Berkeley Laboratory, Berkeley, CA
Electric Power Research Institute, Palo Alto, CA
Data Resources, Inc., Lexington, MA
LCG Consulting, Los Altos, CA
HBRS, San Francisco, CA
XENERGY, Inc., Burlington, MA
Mississippi State University, Starkville, MS
University of Tennessee at Martin, Martin, TN
East Tennessee State University, Johnson City, TN
Memphis State University, Memphis, TN
Middle Tennessee State University, Murfreesboro, TN
Eastern Kentucky University, Richmond, KY
University of Alabama at Huntsville, Huntsville, AL
Tennessee State University, Nashville, TN
Virginia Tech, Blacksburg, VA
Western Carolina University, Cullowhee, NC
Louisiana State University, Baton Rouge, LA
TRADE OR INTEREST GROUP
ASSOCIATIONS
----------------------------------------------------- Appendix III:1.6
American Public Power Association, Washington, DC
Edison Electric Institute, Washington, DC
Electricity Consumers Resource Council, Washington, DC
Institute for Nuclear Power Operations, Atlanta, GA
National Rural Electric Cooperatives Association, Washington, DC
Tennessee Valley Industrial Coalition/Associated Valley Industries,
Columbia, TN
Tennessee Valley Public Power Association, Chattanooga, TN
Tennessee Valley Energy Reform Coalition, Knoxville, TN
TVA DISTRIBUTORS
----------------------------------------------------- Appendix III:1.7
Bristol, VA
Chattanooga, TN
Decatur, AL
Huntsville, AL
Four County Electric Power Association, Columbus, MS
Fort Payne, AL
Knoxville, TN
Memphis, TN
Nashville, TN
(See figure in printed edition.)Appendix IV
COMMENTS FROM THE TENNESSEE VALLEY
AUTHORITY
========================================================= Appendix III
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Note: GAO comments on TVA's executive summary are found in chapter
5.
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See comment 1.
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See ch. 5.
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14, and 22.
See comment 12.
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See comment 14.
See comment 15.
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See comment 15.
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See comment 17.
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See comment 18.
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See ch. 5.
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See ch. 5.
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See comment 21.
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See comment 22.
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See comment 23.
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See comment 21.
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The following are GAO's comments on TVA's letter dated June 15, 1995.
1. We agree with TVA that differences exist between the amounts and
types of regulation faced by publicly-owned and cooperative utilities
and private ones (i.e., IOUs). However, we disagree with TVA's view
that (1) publicly-owned and cooperative utilities receive almost no
oversight from public utility commissions and (2) TVA does not need
regulatory oversight because it is publicly owned. Regarding the
first point, TVA pointed out that publicly- owned utilities are
overseen by municipal or independent boards, or boards comprised of
customer-owners. Moreover, according to a 1992 study by the National
Association of Regulatory Utility Commissioners, 21 states (out of 46
with rural electric cooperatives) regulate the rates of those
cooperatives. TVA does not receive these types of scrutiny.
Regarding the second point, TVA's decisions to invest billions of
dollars in nonproducing assets over an extended time period using
debt financing may indicate that TVA merits special regulatory
attention in order to better safeguard the interests of both TVA's
ratepayers and the federal government.
2. As stated in appendix III, we did not review the effectiveness of
TVA's IRP process in appendix I because it is subject to change and
the final IRP was not scheduled to be completed until December 1995.
We reviewed the preliminary draft of TVA's IRP, presented to the IRP
Review Group on May 31, 1995, and concluded that the information it
contains provides further support for some of the major conclusions
in our report. For example, on the basis of the potential
recommendations in TVA's preliminary draft, key TVA decisions about
the future of Watts Bar 2 would continue to be deferred until the
year 2000 and TVA would also study for 18 to 24 months a potential
option to convert the two Bellefonte units to another fuel source.
As a result of this information, we conclude in chapter 5 that it is
no longer reasonable for TVA to defer the $6.2 billion of costs
related to these units from current revenue requirements. Moreover,
it proposed plans that the Board may or may not act upon in the
future. We have updated the information included in appendix I to
recognize that the preliminary draft was provided to the IRP Review
Group on May 31, 1995, and TVA issued a draft IRP plan to the public
at the end of July 1995.
3. We show in our report how TVA's residential, commercial, and
industrial rates compare with the nine IOUs. We note that TVA's
rates, while low, are not the lowest compared to neighboring
utilities. TVA states that its low operation and maintenance costs
will be a crucial factor in future rates. We continue to believe
that TVA's enormous financing costs and deferred assets are the key
to the competitiveness of TVA's future rates. Inclusion of deferred
assets in TVA's revenue requirements will put significant pressure on
TVA to raise its rates in the future.
TVA states that the interest component of deferred assets is included
for TVA but that IOUs have not included these costs in current rates.
TVA has not capitalized interest related to the Watts Bar 1 and
Bellefonte plants since 1990. However, of TVA's $14 billion in
deferred assets at September 30, 1994, over $5 billion represents
interest capitalized during the lengthy construction of these assets,
which is excluded from current rates. In addition, we compared TVA's
current capitalization of interest to similar capitalized costs of
the neighboring IOUs and found that, for fiscal year 1994, TVA
capitalized $123 million of interest, whereas similar capitalized
costs for the 9 IOUs ranged from $0 to $112 million, with 8 of the 9
IOUs having $29 million or less. Thus, in addition to the $5 billion
of capitalized interest related to deferred assets, TVA is currently
deferring more interest expense from current rates than neighboring
IOUs.
4. We have revised our report to reflect that at the end of fiscal
year 1994, TVA's appropriated debt was $390 million. This amount
represents the
$1 billion repayment required by law less the $610 million repaid at
September 30, 1994. We consider the balance to be repaid as
appropriated debt because TVA must repay this amount to the Treasury
with interest and, therefore, it has the same effect on TVA as any
other debt obligation.
5. Based on additional information provided by TVA, we have revised
our report to reflect that TVA's outstanding line of credit as of
September 30, 1994, was $126 million.
TVA stated that our definition of capitalization in footnote 7 was in
error because it did not include current taxes payable, deferred
taxes payable, and deferred investment-tax credits for IOUs. We
disagree with TVA's definition of capitalization. Industry practice
as indicated by all nine of the IOU annual reports we reviewed does
not include these items in capitalization. Further, TVA's inclusion
of these items in capitalization is inconsistent with the Palmer
Bellevue study, which does not include deferred taxes payable in
capitalization for IOUs.
6. We agree that TVA is subject to congressional and Office of
Management and Budget review.
7. Book value represents the costs of assets that must be included
in TVA's future revenue requirements. The primary purpose of our
analysis was to show that inclusion of TVA's nonproducing assets in
revenue requirements will put pressure on TVA to raise its rates. A
market value analysis of TVA's assets is not relevant to revenue
requirements.
8. We agree 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.
9. As reflected in the table in TVA's comments and table 2.3 of our
report, TVA and American Electric Power have about the same amount of
system capacity. We also state in our report that TVA had net total
assets that were double those of American Electric Power. The major
purpose of our comparison between TVA and American Electric Power was
to show that primarily because of its investment in nonproducing
assets, TVA had almost twice the investment in assets in 1994 as
American Electric Power, yet TVA produced approximately the same
amount of power and revenues from its operations. Our analysis also
highlights that TVA has far more total net assets than American
Electric Power--costs that TVA will have to recover in future revenue
requirements. We have added a footnote to table 2.3 to reflect that
nearly $8 billion of TVA's deferred assets are associated with Watts
Bar 1 and Browns Ferry 3 and that TVA's capacity would increase by
about 2,230 MW if these units become operational.
10. We agree that Kentucky Utilities has lower rates than TVA and
relatively tight capacity margins. However, TVA is incorrect in
saying that because Kentucky Utilities has not built new capacity, it
cannot market power in competition with TVA. As stated in our
report, a Kentucky Utilities official said that the utility has
sufficient existing capacity to compete for some of TVA's smaller
customers, generally those with loads of 100 MW or less. TVA's
comments do not acknowledge that other low-cost utilities in the
region, such as American Electric Power, have surplus capacity and,
therefore, would be able to compete for some of TVA's larger
customers. In addition, TVA does not acknowledge the threat of
competition from IPP's. Several companies have recently developed
natural-gas fired generating units that are 50 percent more efficient
than earlier units and require minimal capital investment. IPP's
typically use such new technologies to generate electricity, which
places downward pressure on electricity rates.
The comparison of investment in PP&E per MW of generating capacity to
rates was used to illustrate the general relationship between these
two items. The fact that this relationship does not hold true for
each utility does not diminish its general validity. The chart shows
that because of TVA's comparatively large investment in PP&E, its
rates are likely to increase in the future when it begins to
recognize the costs of its deferred assets in its revenue
requirements.
11. In chapter 3, we show the cost overruns and schedule slippage
TVA has experienced in its nuclear program and also recognize that
TVA faces the need for a substantial investment in its aging coal and
hydroelectric plants. We further recognize that TVA anticipates
spending hundreds of millions of dollars annually for the next 26
years to upgrade these plants. We concluded that further delays in
completing the construction of its nuclear plants could limit capital
funds available for needed improvements to coal and hydroelectric
plants, especially if TVA honors its commitment to maintain its debt
at below $28 billion. Our report recognizes TVA's efforts, beginning
in 1991, to initiate a capital improvement program for its coal and
hydroelectric plants and TVA's future significant funding plans
through the year 2020. TVA's comments do not mention that Watts Bar
1 is again delayed from December 1995 to February 1996 and has
exceeded its latest budget targets.
TVA states that our analysis of first-year operating costs for
nuclear units is "incorrect" and leads to "erroneous conclusions"
about expected costs. TVA further states that a panel of experts
independent of TVA performed a thorough analysis of TVA's nuclear
assumptions used in the IRP and has not indicated any potential
conflicts. We reviewed the analysis done by the panel of experts in
February 1995 and found that there was no analysis of TVA's estimated
cost to complete Watts Bar 1 and Browns Ferry 3. As our analysis in
chapter 3 shows, cost to complete these units is one of the two most
significant factors in determining future incremental costs. Since
fiscal year 1990, Watts Bar 1 and Browns Ferry 3 have had cost
overruns of over $2.7 billion. On the basis of TVA's fiscal year
1994 expenditures, TVA's further schedule slippage for Watts Bar 1's
commercial operation date from October 1995 to February 1996 will
result in an additional cost overrun of about $130 million. We
continue to believe that the cost of completing these two units may
be higher than TVA anticipated.
12. Our report was not intended to imply that TVA was continuing to
maintain that Watts Bar 1 qualifies for an operating license. We
have clarified this point in our report. In addition, we have
updated our report to show TVA's latest schedule change and NRC's
views of TVA's recent performance at Watts Bar 1. In its comments,
TVA referred to 27 major corrective action programs, but NRC lists 28
programs. We used NRC's number in our report.
13. Our report states that Browns Ferry 3's construction activities
have been on schedule for over a year.
14. Our report states that an assumption of one additional year's
delay in the estimated date of commercial operation for Watts Bar 1
would not be inconsistent with its long construction history. Watts
Bar 1 has been under construction for over 22 years and since 1990
the estimated date of commercial operation has slipped by nearly 4
years. As discussed under comment 11, the commercial operation date
for Watts Bar 1 was recently delayed again. To provide a reasonable
basis for estimating the range of possible cost increases, our report
calculates the cost of a delay based on the average amount TVA spent
per day during fiscal year 1994 at the unit, $1.1 million.
Our analysis used capacity factors of both 66 percent and 38 percent
to demonstrate the sensitivity of TVA's estimate for Watts Bar 1's
first year incremental cost to this factor and provide a range of
possible outcomes. The 66 percent capacity factor acknowledges the
recently improved performance of TVA's nuclear program. The 38
percent capacity factor is based on the combined average capacity
factor for TVA's 5 licensed nuclear units since their original
start-up. This lower assumption is used to illustrate what could
happen to first year incremental costs if TVA incurred significant
problems after bringing the unit into commercial operation. For
example, for the 3 years ending in 1994, the average capacity factor
for 2 of TVA's 3 operating nuclear units--Sequoyah 1 and 2--was about
50 percent.
15. In discussing TVA's coal and hydroelectric programs, we
recognize TVA's past performance, the capital improvement program
initiated in 1991, and TVA's plans for spending billions of dollars
during the next 26 years. Our report also states that TVA has met
Phase 1 requirements, and we acknowledge that, according to TVA, the
availability of coal and hydroelectric units to produce power has
improved, unexpected forced outages have declined, and the cost of
producing power has decreased. We do not state in the report that
TVA's capital expenditures for its coal and hydroelectric plants are
unusual, but rather that these costs are substantial. This is
especially true given TVA's limited remaining borrowing authority and
its history of delays and cost overruns at Watts Bar 1 and Browns
Ferry 3.
16. Although some distributors praised TVA's rate freeze, several
distributors we contacted voiced concerns about TVA's debt and
potential rate increases. Most of the distributors we contacted,
including some of TVA's largest ones, stated they would like to
satisfy at least partial requirements from outside sources. Most TVA
distributors we contacted said that TVA's contracts, which self-renew
automatically every year and contain 10-year advance notice
cancellation requirements, are too stringent, and deny distributors
the source flexibility needed to function in a competitive
environment.
17. TVA's comments inaccurately indicate that our report does not
recognize the positive steps taken by TVA. We disagree that the
extent of these changes will make TVA a successful competitor in the
new marketplace. According to financial analysts, utilities with
large deferred regulatory assets and high fixed costs related to
prior investments will be at greater financial risk than other
utilities.
The statement in our report concerning industrial load refers to a
gain in TVA's load stability due to the departure of some of TVA's
industrial load during the 1980s. We agree, as stated in our report,
that industrial customers are always looking for better rates.
18. We take no position regarding the validity of the study by GDS
Associates or TVA's analysis of this study. Our discussion is
strictly descriptive, showing that a TVA distributor is actively
seeking to buy power from sources other than TVA.
We do however disagree with TVA's comment concerning monetary damages
in its electric power contracts. If a distributor cancels its power
contract with TVA, provisions in the contracts would require a
distributor to pay for a "minimum bill amount," a percentage of the
capacity specified in the contract.
19. According to TVA's fiscal year 1994 financial statements, about
$3.3 billion of TVA's debt was short-term debt with less than a
1-year term to maturity, and about $5.1 billion was long-term debt
maturing between fiscal year 1996 and fiscal year 1998. Our report
illustrates TVA's interest rate risk by stating that if the interest
rates at which TVA must refinance its approximately $8.4 billion in
debt maturing by 1998 increase by 1 percent, TVA's annual financing
costs will increase by about $84 million.
20. We believe because of TVA's substantial debt and resultant
financing costs, it is doubtful that TVA will be able to successfully
compete in the long run. As a result, we discuss a number of options
available to TVA, including a rate increase, that could help to
reduce its debt and financing cost and highlight issues for
consideration in analyzing these options. TVA's comments correctly
recognize that if TVA raised its electricity rates, certain issues
would need to be considered, including the impact a rate increase
might have on TVA's competitive position. However, we estimate that
even a 10 percent rate increase would leave TVA with $23 billion of
outstanding debt and significant financing costs after 10 years.
21. In chapter 5, we state that resolving TVA's financial problems
will be costly and require painful decisions. We believe it is
unlikely that TVA can solve its problems on its own and that some
form of federal government intervention may be required. The options
we present for the Congress to consider include a "no action" option,
limiting or restructuring TVA's debt, removing statutory barriers to
competition, privatizing TVA, and/or increasing oversight of TVA's
activities. There may well be other alternatives. TVA raises
objections to all options presented except the "no action" option.
Resolving TVA's financial situation likely will require a combination
of actions. We did not intend to present a particular solution to
TVA's dilemma; rather, we wanted to stimulate a dialogue among the
key decisionmakers concerning options available to protect the
government's interests and help TVA fulfill its announced intention
of becoming a competitive and financially viable utility.
TVA states that it "has offered to pay off the debt owed to the
federal government" which "would have been a benefit to the U.S.
taxpayer and at the same time allowed TVA to reduce operating costs."
Most of TVA's federal debt is owed to the Federal Financing Bank
(FFB) and has no call provisions. We agree that allowing TVA to
refinance its FFB debt by issuing its own bonds would reduce TVA's
interest expense since most of this debt is currently at a higher
interest rate than recent issuances of TVA bonds. However, TVA is
incorrect in assuming this refinancing transaction would benefit the
U.S. taxpayer. TVA's FFB debt had interest rates ranging from 7.3
percent to 11.7 percent at September 30, 1994, while Treasury Bill
yields for the week ended July 28, 1995, ranged from 5.7 percent for
1 year to 6.9 percent for 30 years. Thus, without a substantial
refinancing premium paid by TVA, this transaction would result in a
greater decrease in interest income than the decrease in interest
expense for the federal government.
TVA states that "TVA and distributors currently pay approximately 25
percent more in tax-equivalent payments to state and local
governments than IOUs." Determining whether this statement is true
was beyond the scope of our review; however, we did find that TVA
paid no federal income tax and on the average, the IOUs paid more
than twice as much in total taxes as TVA.
22. As shown under comment 2, in appendix I we did not review the
effectiveness of TVA's IRP process. Because TVA's "preliminary
draft" of the IRP proposes that TVA continue to defer key decisions
about Watts Bar 2 and the two Bellefonte units and because the
preliminary draft will not be acted upon by the Board until January
1996, information contained therein provided further support for some
of the major conclusions of this report.
23. While it is true that DRI has revised its growth estimate for
the region upward since its 1994 forecast (ranked ninth or last among
the nine regions; it was moved to seventh in their latest forecast),
DRI's projected growth for the East-South Central region is still
less than the national average and less optimistic than TVA's
projected growth for the power service area.
24. Overall, we believe that the Palmer Bellevue study is incomplete
and presents an optimistic view of TVA's competitiveness because its
calculation of TVA's incremental and average cost of producing
electricity excludes TVA's $1.9 billion of annual interest expense
and TVA's other fixed costs, such as depreciation expense. We
believe that the full cost of producing electricity is more relevant
to a utility's current and future competitiveness. A utility cannot
sell electricity at incremental costs (or average costs as calculated
by Palmer Bellevue) for too long and remain financially viable.
25. We disagree that our report is inconsistent. Taking down the
"fence" and opening TVA up to competition is a complicated matter.
While subjecting TVA to competition would force it to operate in a
more businesslike manner, our report states that TVA's substantial
financing costs and deferred assets make it unlikely that it can
compete successfully with neighboring IOUs in the long term. In
order for TVA to compete effectively, costly and painful decisions
need to be made.
26. To clarify our position, we doubt that if TVA were subject to a
public utility commission whether it would have been allowed to incur
$14 billion for nonproducing assets over a 20-year period. Our
report does not assert that state regulators force utilities to
immediately begin reflecting capital and interest costs associated
with unfinished or abandoned plants in their rates. Rather, our
report states that utilities are "quickly absorbing into rates or
writing off costs associated with uneconomical plants."
TVA'S USE OF IN-SUBSTANCE
DEFEASANCE OF DEBT AS A
REFINANCING TOOL
=========================================================== Appendix V
As part of our review, we analyzed whether defeased debt should be
included as part of overall debt for purposes of determining whether
TVA had exceeded its statutory $30 billion debt limit. This appendix
describes TVA's use of in-substance defeasance of debt as a
refinancing mechanism. We also discuss the accounting, budgetary,
and financial implications of these transactions and assess the
reasonableness of TVA's position that defeased debt should not be
included in the $30 billion debt limit. We briefed the requesters'
staff on our analysis of the in-substance defeasance issues during
September and December 1994 meetings.
DESCRIPTION OF IN-SUBSTANCE
DEFEASANCE OF DEBT
------------------------------------------------------- Appendix V:0.1
As interest rates began to fall in recent years, TVA has looked for
ways to lower interest expense on existing debt. Beginning in 1989,
TVA began refinancing high interest rate bonds by using in-substance
defeasance arrangements. An in-substance defeasance of debt occurs
when the borrower creates a trust with an independent trustee and
irrevocably funds it with essentially risk-free monetary assets so
that the cash flow from the trust assets is sufficient to service the
outstanding debt. Specifically, TVA issues new debt and the proceeds
are used to purchase investments (direct obligations of the U.S.
government) that are sufficient to service the original debt
including interest payments. The investments purchased from the
proceeds of the new debt are placed into an irrevocable trust. This
arrangement results in retiring the original debt and refinancing it
with new debt at a lower interest rate.
FINANCIAL IMPLICATIONS
------------------------------------------------------- Appendix V:0.2
TVA has used in-substance defeasance of debt primarily to refinance
its Federal Financing Bank (FFB) debt at lower interest rates. Since
1989, $12 billion of debt has been refinanced through defeasance,
with $7.5 billion of this debt being FFB debt issued between 1980 and
1984 at interest rates ranging from 10.4 percent to 14.9 percent.
As of September 30, 1994, there were three outstanding bond issues
totalling approximately $3.8 billion that had been defeased. The
first two issues, totalling approximately $2.6 billion, matured on
October 1, 1994. The third issue, totalling approximately $1.2
billion, will mature on November 15, 1996.
To illustrate the impact of these refinancing transactions, we will
use the $1.2 billion debt issue. In this example, an in-substance
defeasance arrangement was used to refinance the $1.2 billion of debt
which has an interest rate of 8.25 percent. The new bonds that were
issued to generate sufficient proceeds to defease the $1.2 billion
issue had maturities of 3 and 50 years and interest rates of 4.6
percent and 6.9 percent, respectively.
ACCOUNTING TREATMENT
------------------------------------------------------- Appendix V:0.3
TVA's in-substance defeasance of debt transactions are being
accounted for in accordance with Statement of Financial Accounting
Standards No. 76 (SFAS 76), Extinguishment of Debt. Debt that is
treated in accordance with circumstances established by SFAS 76 is
considered extinguished for financial reporting purposes and is
removed from the balance sheet. TVA's in-substance defeasance
transactions previously described clearly fall within the
circumstances described in SFAS 76. TVA's use of direct obligations
of the U.S. government as trust assets satisfies the funding
requirements of SFAS 76. Coopers and Lybrand L.L.P. TVA's
independent auditor, has reviewed these transactions and concurred
with TVA's treatment for financial reporting purposes.
BUDGETARY IMPLICATIONS
------------------------------------------------------- Appendix V:0.4
As previously mentioned, TVA's electricity operations are included in
the overall federal budget. TVA's $26 billion of debt at September
30, 1994, has been included in previous years' calculations of the
budget deficit. We found that defeased debt has no impact on the
federal budget. Proceeds from new borrowing are not considered
budgetary receipts, and cash used to defease outstanding debt is not
considered a budgetary outlay.
ASSESSMENT OF TVA'S
TREATMENT OF DEFEASED DEBT
------------------------------------------------------- Appendix V:0.5
Under each of TVA's in-substance defeasance arrangements, the
irrevocable trust agreement requires the deposit of the proceeds of
the sale of new power bonds with an independent trustee. Under the
trust arrangements, the payment of the defeased bonds becomes the
responsibility of the trustee; it is accomplished without further
action by TVA. From TVA's standpoint, therefore, the defeased bonds
were paid when it entered into the irrevocable trust, and the
proceeds of the new bonds were placed under the control of the
independent bond trustee. We believe that TVA has a reasonable basis
for its conclusion.
TVA states that the majority view taken by state courts has been that
the issuance of debt, where the proceeds of which are used to refund
outstanding debt, does not result in an increase of outstanding debt
for the purpose of state statutory or constitutional limitations.
MAJOR CONTRIBUTORS TO THIS REPORT
========================================================== Appendix VI
ACCOUNTING AND INFORMATION
MANAGEMENT DIVISION,
WASHINGTON, DC
-------------------------------------------------------- Appendix VI:1
Gregory D. Kutz, Assistant Director
Donald R. Neff, Senior Audit Manager
Caryn Catignani, Auditor
Glenn A. Thomas, Financial Analyst
RESOURCES, COMMUNITY, AND
ECONOMIC DEVELOPMENT DIVISION,
WASHINGTON, DC
-------------------------------------------------------- Appendix VI:2
Bernice Steinhardt, Associate Director
Ernie Hazera, Deputy Project Manager
Mehrzad Nadji, Assistant Director - Economic Analysis Group
Timothy J. Guinane, Senior Economist
Michael F. Duffy, Senior Evaluator
Cassandra Joseph, Senior Evaluator
OFFICE OF THE GENERAL COUNSEL,
WASHINGTON, DC
-------------------------------------------------------- Appendix VI:3
Thomas H. Armstrong, Assistant General Counsel
Doreen S. Feldman, Assistant General Counsel
Jackie Goff, Senior Attorney
Amy M. Shimamura, Senior Attorney
ATLANTA REGIONAL OFFICE
-------------------------------------------------------- Appendix VI:4
John P. Hunt, Jr., Project Manager
Martha C. Vawter, Site Senior
Suzanne Murphy, Auditor
Philip Amon, Evaluator
Stacey E. Keisling, Evaluator
Pamela A. Scott, Reports Analyst
*** End of document. ***