United States General Accounting Office

GAO Report to Congressional Requesters

August 1995 TENNESSEE VALLEY

AUTHORITY

Financial Problems

Raise Questions About

Long-term Viability

GAO/AIMD/RCED-95-134

GAO United States

General Accounting Office

Washington, D.C. 20548

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
B-259411 

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

Page 2 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Executive Summary

Purpose 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 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 TVA is $26 billion in debt and has invested $14 billion in nonproducing

nuclear assets (called “deferred assets”) that are not included in its

Page 3 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Executive Summary

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

TVA’s Financial Condition

Puts It at a Competitive

Disadvantage

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

Page 4 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Executive Summary

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

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

Page 5 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Executive Summary

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

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

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

Page 6 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Executive Summary

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 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

Page 7 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Executive Summary

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.

Page 8 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Page 9 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Contents

Executive Summary 3

Chapter 1 

Introduction

14

Authorizing Legislation Established TVA as a Wholly-Owned

Government Corporation

16

Legislative Changes Create a Competitive Electricity Market for

Other Utilities

18

History of TVA’s Nuclear Power Program 20

Objectives, Scope, and Methodology 22

Chapter 2 

TVA’s Financial

Condition Will Make It

Difficult to Compete

24

TVA Has Substantial Debt and Significant Costs for

Nonproducing Nuclear Assets

24

TVA Has Substantially Higher Financing Costs and Deferred

Assets Than Neighboring Utilities

32

TVA’s Average Retail Rates Are Mixed Compared to Neighboring

Utilities but Exclude Substantial Costs

37

Chapter 3 

Continuing Cost

Overruns in Nuclear

Program Could

Impact Other Power

Resources

41

Construction Activities at Two Nuclear Units Continue to

Increase Debt and Deferred Assets

41

Cost for Nuclear Construction Could Affect Coal and

Hydroelectric Program Improvements

47

Chapter 4 

TVA Is Protected

From Competition in

the Short Term

51

Other Utilities Are Changing to Meet New Competitive Pressures 51

TVA Has Taken Some Actions to Enhance Its Competitiveness 53

In the Short Run, Several Factors May Protect TVA From

Competition

57

TVA’s Customers React to Evolving Markets 60

Chapter 5 

Options for

Addressing TVA’s

Problems

63

TVA’s Actions, Plans, and Other Options Are Unlikely to Make It

Fully Competitive or to Protect Federal Financial Interests

63

Options for Congressional Consideration 67

Agency Comments and Our Evaluation 72

Page 10 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Contents

Appendixes Appendix I: TVA’s Integrated Resource Planning Process 80

Appendix II: Review of TVA’s Load Forecasting 94

Appendix III: Objectives, Scope, and Methodology 107

Appendix IV: Comments From the Tennessee Valley Authority 117

Appendix V: TVA’s Use of In-substance Defeasance of Debt as a

Refinancing Tool

155

Appendix VI: Major Contributors to This Report 157

Tables Table 1.1: Status of TVA’s Originally Planned 17 Nuclear Units as

of July 1995

22

Table 2.1: Estimated Annual Increase in Revenue Requirements

for Nonproducing Nuclear Assets as of September 30, 1994

32

Table 2.2: Comparison of Key Financial Ratios for TVA and

Neighboring IOUs, 1994

35

Table 2.3: Fiscal Year 1994 Key Statistics for TVA and American

Electric Power

36

Table 3.1: Watts Bar 1 Estimated Costs and Scheduled Operation

Dates as of the End of the Last 5 Fiscal Years

42

Table 3.2: Browns Ferry 3 Estimated Costs and Scheduled

Operation Dates as of the End of the Last 5 Fiscal Years

43

Table 3.3: Estimate of First Year Incremental Cost Analysis For

Watts Bar 1

45

Figures Figure 1.1: Map of TVA’s Service Area 15

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

26

Figure 2.2: TVA’s $32 Billion in Total Capitalization and Liabilities

as of September 30, 1994

28

Figure 2.3: TVA’s $19.3 Billion in Net Nuclear Property, Plant, and

Equipment as of September 30, 1994

30

Figure 2.4: Map of Service Areas of TVA and Neighboring IOUs 33

Figure 2.5: TVA’s and Neighboring Utilities’ Average Retail

Residential, Commercial, and Industrial Rates for 1993

38

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

40

Figure 3.1: TVA’s Three Operating Nuclear Units’ Average

Capacity Factor Since Restart, as of September 30, 1994

46

Page 11 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Contents

Figure 3.2: TVA’s Five Licensed Nuclear Units’ Average Capacity

Factor Since Original Start-Up

47

Figure 3.3: TVA Power Generation by Fuel Source, Fiscal Years

1980-1994

48

Figure 3.4: TVA’s Capital Expenditures for Coal and

Hydroelectric Generation in Constant 1994 Dollars, Fiscal Years

1980-1994

49

Figure 4.1: Plans of TVA’s Neighboring IOUs to Satisfy Additional

Demand Through 2003

52

Figure 4.2: TVA’s Total Interest Expense, Fiscal Years 1988-1994 54

Figure I.1: TVA’s IRP Process Building Blocks 83

Figure II.1: Simplified Representation of TVA’s Load Forecasting

System

95

Figure II.2: Accuracy of TVA’s Medium-term Historic Load

Forecasts

99

Figure II.3: Growth in Electricity Load Forecast by TVA,

Neighboring Utilities, and the Energy Information Administration

for 1994-2003

101

Figure II.4: Growth in Electricity Peak Demand Forecast by TVA

and Neighboring Utilities for 1994-2003

102

Figure II.5: Growth in Total Employment Forecast by TVA and

Data Resources, Inc., for 1994-2004

104

Figure II.6: Growth in Manufacturing Employment Forecast by

TVA, Data Resources, Inc., and the Energy Information

Administration for 1994-2004

105

Page 12 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Contents

Abbreviations

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

Page 13 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 1 

Introduction

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.

1

A megawatt is one million watts of electricity.

Page 14 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 1 

Introduction

Figure 1.1: Map of TVA’s Service Area

Bristol, VA

Alabama

Mississippi

Kentucky

Georgia

Columbus

Memphis

Huntsville

Chattanooga

Nashville

Knoxville

Virginia

North Carolina

Tennessee

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.

Page 15 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 1 

Introduction

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.

Authorizing

Legislation

Established TVA as a

Wholly-Owned

Government

Corporation

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).

Page 16 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 1 

Introduction

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 Board5

 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

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.

Page 17 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 1 

Introduction

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.

Legislative Changes

Create a Competitive

Electricity Market for

Other Utilities

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

plants7

 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

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.

Page 18 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 1 

Introduction

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

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.

Page 19 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 1 

Introduction

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.

History of TVA’s

Nuclear Power

Program

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

Page 20 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 1 

Introduction

almost $5 billion10 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.

10Unless noted otherwise, amounts in this report are in current-year dollars.

Page 21 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 1 

Introduction

Table 1.1: Status of TVA’s Originally

Planned 17 Nuclear Units as of

July 1995 Nuclear plants/units

Year construction

started

Year commercial

service began Current status

Browns Ferry

unit 1

unit 2

unit 3

1967

1967

1968

1974

1975

1977

shutdowna

operating

constructionb

Sequoyah

unit 1

unit 2

1970

1970

1981

1982

operating

operating

Watts Bar

unit 1

unit 2

1973

1973

1996c

none

construction

unfinisheda

Bellefonte

unit 1

unit 2

1974

1974

none

none

unfinisheda

unfinisheda

Phipps Bend

unit 1

unit 2

1977

1977

none

none

cancelled 1982

cancelled 1982

Hartsville

A units 1&2

B units 1&2

1976

1977

none

none

cancelled 1984

cancelled 1982

Yellow Creek

unit 1

unit 2

1978

1978

none

none

cancelled 1984

cancelled 1984

aConsidered to be in “mothballed” status.

bBrowns 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.

cTVA’s estimated date of commercial operation is February 1996.

Source: GAO analysis of TVA data.

Objectives, Scope,

and Methodology

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

Page 22 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 1 

Introduction

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.

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TVA’s Financial Condition Will Make It

Difficult to Compete

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 assets2

 have not been included in TVA’s revenue

requirements3

 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 assets4 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.

TVA Has Substantial

Debt and Significant

Costs for

Nonproducing

Nuclear Assets

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

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.

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.

Page 24 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
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TVA’s Financial Condition Will Make It

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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.

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TVA’s Financial Condition Will Make It

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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

Assets

Nuclear generation


($19.3 billion)

15.8%

68.7%

12.0%


Transmission system & 


other ($3.4 billion)


Coal generation ($4.4 billion)


2.9%


Hydro & multi purpose generation 


($0.8 billion)

0.6%


Combustion turbine generation


($0.2 billion)

Power Generation

Coal


(92.1 billion KWH)

Hydro (20.2 billion KWH)


Nuclear (18.4 billion KWH)


0.2%


Combustion turbine 


(0.2 billion KWH)

15.4%

14.0%

70.4%

Note: Assets are net of accumulated depreciation.

Source: TVA 1994 financial statements.

Substantial Debt Incurred 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

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TVA’s Financial Condition Will Make It

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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 capitalization7

 and liabilities

by balance sheet account.

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.

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TVA’s Financial Condition Will Make It

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Figure 2.2: TVA’s $32 Billion in Total

Capitalization and Liabilities as of

September 30, 1994

69.7% • Long-term debt ($22.2 billion)

•

10.4%

Short-term debt ($3.3 billion)

•

10.8%

Retained earnings ($3.4 billion)

•

7.0%

Current & other liabilities ($2.2

billion)

•

2.0%

Appropriated debt & investment

($0.6 billion)

Debt applicable to TVA’s $30 billion limit

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.

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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.

TVA Has Deferred

Significant Costs

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.

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.

10Depreciation 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.

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TVA’s Financial Condition Will Make It

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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

40.3% • Construction in progress ($7.8

billion)

32.1%•

Deferred nuclear units ($6.2

billion)

•22.3%

Net completed plant ($4.3 billion)

•

5.3%

Nuclear fuel ($1.0 billion)

Capital costs excluded from current rates.

Capital costs included in current rates.

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,

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TVA’s Financial Condition Will Make It

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93 percent of TVA’s gross nuclear PP&E as of September 30, 1994, must be

paid for by future ratepayers.

Nonproducing Nuclear

Assets Will Impact

Revenue Requirements

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

11The 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.

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TVA’s Financial Condition Will Make It

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Table 2.1: Estimated Annual Increase

in Revenue Requirements for

Nonproducing Nuclear Assets as of

September 30, 1994

Dollars in billions

Nonproducing

nuclear assets

Total estimated

cost to be

depreciated/

amortizeda

Estimated

depreciation/

amortization

period (in years)

Estimated annual

increase in

revenue

requirements

Deferred Nuclear Units

Watts Bar 2

Bellefonte 1

Bellefonte 2 $6.2 30 $0.207

Construction In Progress

Watts Bar 1 6.8 40 0.170

Browns Ferry 3 1.7 22 0.077

Total $14.7 /— $0.454

aTotal 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.

TVA Has Substantially

Higher Financing

Costs and Deferred

Assets Than

Neighboring Utilities

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.

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TVA’s Financial Condition Will Make It

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Figure 2.4: Map of Service Areas of TVA and Neighboring IOUs

Entergy Southern 

Company

Carolina Power & Light

Duke Power

American Electric


Power

LG&E Energy Corp.

Illinova

Dominion Resources

KU Energy

Neighboring Utilities


TVA

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,

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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 operations12 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

12Net 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.

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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

Indicators of flexibility Indicators of deferred assets

(Figures in percent)

Utility

Financing costs

to revenue

Fixed financing

costs to revenue

Net cash from

operations to

expenditures for

PP&E and CSD

Accumulated

depreciation/

amortization to

gross PP&E

Deferred assets

to 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

Average 16 8 95 35 3

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.

Page 35 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 2 

TVA’s Financial Condition Will Make It

Difficult to Compete

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) 25,913a 23,670

System sales (in millions of kilowatt hours) 122,574 116,714

Net total assets $31,842 $15,713

Deferred assetsb $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 expense $639 $572

aRepresents 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.

bDeferred 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.

Page 36 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 2 

TVA’s Financial Condition Will Make It

Difficult to Compete

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.

TVA’s Average Retail

Rates Are Mixed

Compared to

Neighboring Utilities

but Exclude

Substantial Costs

TVA’s average retail13 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.

13Retail rates are the rates paid by the ultimate consumer. For TVA, this would include the cost added

by its wholesale distributors.

Page 37 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 2 

TVA’s Financial Condition Will Make It

Difficult to Compete

Figure 2.5: TVA’s and Neighboring Utilities’ Average Retail Residential, Commercial, and Industrial Rates for 1993

Cents/kilowatt-hour

0

1

2

3

4

5

6

7

8

9

10

11

12

Illinova Entergy Carolina

Power &

Light

Dominion

Resources

Southern

Company

Duke Power American

Electric

Power

LG&E

Energy

Corp.

KU Energy TVA

Utility company

10.2

8.3

4.4

8.7

7.7

5.1

8.3

6.9

5.5

8.0

6.2

4.4

7.3 7.0

4.5

7.3

6.0

4.3

6.2

5.6

3.6

6.0

5.6

3.8

4.5 4.3

3.4

5.9 5.9

3.9

Residential

Commercial

Industrial

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

14Notice of Proposed Rulemaking and Supplemental Notice of Proposed Rulemaking (70 FERC 61.357),

FERC (Mar. 29, 1995).

Page 38 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 2 

TVA’s Financial Condition Will Make It

Difficult to Compete

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.

Page 39 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 2 

TVA’s Financial Condition Will Make It

Difficult to Compete

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

Dollars in PP&E per megawatt Cents per 


kilowatt-hour

900

800

700

600

500

400

300

200

100

Carolina 

Power & 

Light

LG&E 

Energy 

Corp.

American 

Electric 

Power

KU Energy 

1600

1500

1400

1300

1200

1100

1000

7.0

6.5

6.0

5.5

5.0

4.5

3.5

Illinova Dominion 

Resources

TVA Entergy Southern 

Company

Duke 

Power

6.9

6.5

5.2

6.9

6.1

6.8

5.2

5.7

4.8

4.0

1518

1253 1219

1108

998

971

801

772 732

684

4.0

Utility company

Cents per kilowatt-hour

Dollars in PP&E per megawatt

7.5

8.0

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.

Page 40 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 3 

Continuing Cost Overruns in Nuclear

Program Could Impact Other Power

Resources

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

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

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.

Page 41 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 3 

Continuing Cost Overruns in Nuclear

Program Could Impact Other Power

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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

investment at year-end

$4,773 $5,151 $5,553 $6,035 $6,445

TVA estimated cost to

complete

476 805 479 516 355

TVA total

estimated

cost

$5,249 $5,956 $6,032 $6,551 $6,800

Scheduled commercial

operation date

March

1992

March

1994

June

1994

Jan.

1995

Feb.

1996a

aThis 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.”

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Continuing Cost Overruns in Nuclear

Program Could Impact Other Power

Resources

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

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

investment at year-end

$296 $406 $775 $1,171 $1,475a

TVA estimated cost to

complete

510 610 318 780 524

TVA total

estimated 

cost

$806 $1,016 $1,093 $1,951 $1,999

Scheduled commercial

operation date

Jan.

1993

Sept.

1993

March

1994

Dec.

1995

Feb. 

1996

aApproximately $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

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Continuing Cost Overruns in Nuclear

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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

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 capacity1

 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

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.

Page 44 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
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Continuing Cost Overruns in Nuclear

Program Could Impact Other Power

Resources

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

Major assumptionsa

TVA

estimate

Feb.1994 Scenario 1 Scenario 2

Estimated cost-to-completeb (millions of

dollars)

$515 $765 $1,165

Capacity factor

(percentage)

76 66 38

First year incremental cost (cents per kwh) 2.1 2.8 5.6

aFor 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.

bCost-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

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.

Page 45 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
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Continuing Cost Overruns in Nuclear

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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

Percent

0

10

20

30

40

50

60

70

80

90

100

Browns

Ferry 2

Sequoyah 1

Sequoyah 2

Nuclear units

78.3

63.1

58.8

Average capacity factor

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.

Page 46 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
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Continuing Cost Overruns in Nuclear

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Figure 3.2: TVA’s Five Licensed

Nuclear Units’ Average Capacity

Factor Since Original Start-Up

Percent

0

10

20

30

40

50

60

70

80

90

100

Browns

Ferry 1

Browns Ferry 2

Browns Ferry 3

Sequoyah 1

Sequoyah 2

Nuclear units

29.6

40.9

26.9

48.9 52.0

Average capacity factor

Source: GAO analysis of TVA data.

Cost for Nuclear

Construction Could

Affect Coal and

Hydroelectric

Program

Improvements

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.

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Continuing Cost Overruns in Nuclear

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System Generation

Dependent Upon Coal and

Hydroelectric Units

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

Percent

0

10

20

30

40

50

60

70

80

90

100

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994

Fiscal Years

Nuclear

Hydroelectric

Coal

Source: TVA data.

Reduced Capital

Expenditures for Coal and

Hydroelectric Generation

During 1980s

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

Page 48 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
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Continuing Cost Overruns in Nuclear

Program Could Impact Other Power

Resources

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 age3

 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.

Capital Improvement

Program Initiated and

Expenditures Increased

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

Dollars in millions

0

100

200

300

400

500

600

700

800

900

1000

1980 1982 1984 1986 1988 1990 1992 1994

Fiscal years

Source: TVA data.

3

The average age of TVA’s coal and hydroelectric units as of December 1994 was 37 years and 49 years,

respectively.

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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

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.

Page 50 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Chapter 4 

TVA Is Protected From Competition in the

Short Term

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

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 practices1

 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.

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.

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Figure 4.1: Plans of TVA’s Neighboring

IOUs to Satisfy Additional Demand

Through 2003

53.8% • Natural gas

17.1%•

Demand-side management

•12.0%

Purchases

•12.9%

Oil

•

2.6%

Coal

1.6%

Nuclear, Hydropower, and Other

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

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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.

TVA Has Taken Some

Actions to Enhance

Its Competitiveness

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.

2

Kentucky Utilities provides the lowest electricity rates of any of TVA’s neighboring IOUs. It has a

capacity of about 3,700 MW.

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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 Dollars in millions

1000

1100

1200

1300

1400

1500

1600

1700

1800

1900

2000

1988 1989 1990 1991 1992 1993 1994

Fiscal year

1898 1909

1738 1741 1752

1825

1895

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

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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

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.

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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

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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.

In the Short Run,

Several Factors May

Protect TVA From

Competition

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

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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

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

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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

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.

Low-Cost Competitors May

Not Be Able to Sell Power

to TVA Distributors

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.

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).

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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 hour7

 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).

TVA’s Customers

React to Evolving

Markets

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

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

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.

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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

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.

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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.

TVA’s Industrial Customers

Are Concerned, but Praise

TVA’s Efforts to Hold Rates

Steady

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.

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Options for Addressing TVA’s Problems

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

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

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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.

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.

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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

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.

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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.

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Options for

Congressional

Consideration

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.

The “No Action” Option 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.

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.

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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

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

5

Triennial Assessment of the Tennessee Valley Authority—Fiscal Years 1980-1982 (GAO/RCED-83-123,

April 15, 1983).

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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.

Removing Statutory

Barriers to Competition

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 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,

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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.

Increasing Oversight of

TVA Activities

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

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.

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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.

8

Electricity Supply: What Can Be Done To Revive the Nuclear Option? (GAO/RCED-89-67, March 23,

1989).

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• 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.

Agency Comments

and Our Evaluation

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 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.

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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 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

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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 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

9

Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of

Regulation.

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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.

Cash Flow 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

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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 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

Palmer Bellevue states that we give “short shrift” to some important issues

relating to TVA’s competitive position. The Palmer Bellevue comments

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Options for Addressing TVA’s Problems

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.

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.

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Options for Addressing TVA’s Problems

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.

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TVA’s Integrated Resource Planning Process

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

The Energy Policy Act of 1992 requires TVA to conduct a least-cost

planning program1

 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

1

TVA uses the term Integrated Resource Planning when referring to the least-cost planning process

required by the act.

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TVA’s Integrated Resource Planning Process

and comments prior to the selection and addition of any major new energy

resource.

Unlike TVA’s Past IRP

Efforts, TVA’s Current

IRP Includes Public

Participation

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.

The Technical Process Will

Use Teams

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

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.

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TVA’s Integrated Resource Planning Process

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.

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TVA’s Integrated Resource Planning Process

Figure I.1: TVA’s IRP Process Building

Blocks Concerns/Issues


and


Values Objectives

Evaluation


Criteria

Customer Service


Options

Environment

Load


Forecast

Existing 


Capabilities

Supply Side


Options

Ranking of


Options

Strategy


Development Uncertainties

Integration

IRP Plan

Source: TVA.

Issues and Values Translation

Team

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

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TVA’s Integrated Resource Planning Process

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 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

Load Forecasting Team 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

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.

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TVA’s Integrated Resource Planning Process

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 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 capacity5

.

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

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.

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TVA’s Integrated Resource Planning Process

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.

Supply-Side Options Team 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.

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TVA’s Integrated Resource Planning Process

Customer Service Options

Team

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.

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.

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TVA’s Integrated Resource Planning Process

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.

Environment Team 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

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.

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TVA’s Integrated Resource Planning Process

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.

Rankings Team 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 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 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

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TVA’s Integrated Resource Planning Process

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.

Integration Team 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 futures10 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

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.

10TVA refers to a strategy associated with a future as a “scenario.”

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TVA’s Integrated Resource Planning Process

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.

Public Participation

Process

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

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Appendix I 

TVA’s Integrated Resource Planning Process

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

In addition to the multitude of consultants that TVA has utilized in

developing and conducting its IRP process, several additional consulting

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Appendix I 

TVA’s Integrated Resource Planning Process

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

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.

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Appendix II 

Review of TVA’s Load Forecasting

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

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.

TVA Uses Several Different

Models to Forecast Load

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.

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.

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.

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Appendix II 

Review of TVA’s Load Forecasting

Figure II.1: Simplified Representation of TVA’s Load Forecasting System

Electricity


Price

Load Forecasts


for Customer


Classes

Reference


Load and Peak


Forecasts

Professional


Judgement

HELM High, Low


Load and Peak 


Forecasts

Probability 


Tree Model

Natural Gas


Price

Economic


Factors

Key 


Sources


for 


Inputs

Key


Inputs

Hourly 


Load


Forecasting


Model

Customer


Class


Forecasts

Chalkboard


Session

Core


Load


Forecasting


Models

High and


Low


Forecasts

Uncertainty


Analysis

Reference


Forecasts

FINESSE

Other


Sources

REEPS


COMMEND


INFORM


EFM


RESM

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

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Appendix II 

Review of TVA’s Load Forecasting

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.

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.

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Appendix II 

Review of TVA’s Load Forecasting

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.

TVA Uses Region-Specific

Data in Developing Its

Forecasts

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

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

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Appendix II 

Review of TVA’s Load Forecasting

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

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

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 error4

 of TVA’s medium-term load

forecasts declined from 17.7 percent in the 1970s to 2.7 percent in the early

1990s.5

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.

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Appendix II 

Review of TVA’s Load Forecasting

Figure II.2: Accuracy of TVA’s

Medium-term Historic Load Forecasts Mean absolute error in percent

0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

1970-79 1980-89 1990-91 1970-91

Fiscal years of forecasts

17.7

7.1

2.7

11.7

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

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Appendix II 

Review of TVA’s Load Forecasting

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.

TVA’s 1995 Reference Load

Forecast Is at High End of

Range for Neighboring

Utilities

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.

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.

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Appendix II 

Review of TVA’s Load Forecasting

Figure II.3: Growth in Electricity Load

Forecast by TVA, Neighboring Utilities,

and the Energy Information

Administration for 1994-2003

Annual percent growth in gigawatt-hours

0

0.5

1.0

1.5

2.0

2.5

3.0

Dominion

Resources

TVA

SERC Southern Subregion

Duke Power

KU Energy

Energy Information Administration

Entergy

American Electric Power

2.6

2.4

2.1 2.1

1.7

1.5

1.3 1.3

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.

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Appendix II 

Review of TVA’s Load Forecasting

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

Annual percent growth in megawatts

0

0.5

1.0

1.5

2.0

2.5

3.0

TVA

Dominion Resources

Duke Power

SERC Southern Subregion

Entergy

KU Energy

American Electric Power

2.5 2.5

2.3

2.2

1.6 1.6

1.2

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.

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Appendix II 

Review of TVA’s Load Forecasting

TVA’s Key Regional

Economic Growth

Assumption Is More

Optimistic Than Data

Resources, Inc.’s

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.

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.

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Appendix II 

Review of TVA’s Load Forecasting

Figure II.5: Growth in Total

Employment Forecast by TVA and

Data Resources, Inc., for 1994-2004

Annual percent growth

0

0.5

1.0

1.5

2.0

TVA DRI

1.8

1.1

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.

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Appendix II 

Review of TVA’s Load Forecasting

Figure II.6: Growth in Manufacturing

Employment Forecast by TVA, Data

Resources, Inc., and the Energy

Information Administration for

1994-2004

Annual percent growth

-1.5

-1.0

-0.5

0

0.5

1.0

TVA

DRI

Energy Information Administration

0.1

-1.2

-0.3

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.

Other Key Variables That

Affect TVA’s Reference

Forecast Are Reasonable

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

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Appendix II 

Review of TVA’s Load Forecasting

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.

Page 106 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Appendix III 

Objectives, Scope, and Methodology

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

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

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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

1

The fiscal year ends for TVA on September 30 and the IOUs on December 31.

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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.

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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 associations2

 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

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.

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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.

Assessing the Status of

TVA’s Power Program

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

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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

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

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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

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

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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 Luce3

 and Mr.

Robert Fri4

—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.

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Organizations and

Groups That GAO

Contacted

Federal Agencies 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

Standard & Poor’s, New York, NY

Moody’s Investors Service, New York, NY

Fitch Investors Service, Inc., New York, NY

Independent Public

Accounting Firm

Coopers & Lybrand L.L.P.

Neighboring Electric

Utilities or Holding

Companies

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

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

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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

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 Bristol, VA

Chattanooga, TN

Decatur, AL

Huntsville, AL

Four County Electric Power Association, Columbus, MS

Fort Payne, AL

Knoxville, TN

Memphis, TN

Nashville, TN

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Authority

Note: GAO comments

supplementing those in the

report text appear at the

end of this appendix.

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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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Authority

See ch. 5.

See comment 2.

See ch.5.

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See ch. 5.

See comment 3.

See comment 4.

See comment 5.

See comment 6.

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See ch. 5.

See comment 7.

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Authority

See comment 8.

See comment 9.

See comment 3.

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See comment 10.

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See comment 11.

See comments 2,

14, and 22.

See comment 11.

See comment 12.

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See comment 13.

See comment 14.

See comment 15.

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See comment 15.

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See comment 15.

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Authority

See comment 16.

See comment 17.

See comment 18.

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See comment 18.

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Authority

See ch. 5.

See comment 17.

See ch. 5.

See comment 11.

See comment 19.

See ch. 5.

See comment 20.

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See ch. 5.

See comment 21.

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See comment 21.

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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 ch. 5.

See comment 24.

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See comment 25.

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See comment 21.

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See comment 26.

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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

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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.

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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

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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

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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.

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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.

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Comments From the Tennessee Valley

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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.

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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

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Comments From the Tennessee Valley

Authority

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.”

Page 154 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Appendix V 

TVA’s Use of In-substance Defeasance of

Debt as a Refinancing Tool

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

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 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

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Appendix V 

TVA’s Use of In-substance Defeasance of

Debt as a Refinancing Tool

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 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 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

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.

Page 156 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
Appendix VI 

Major Contributors to This Report

Accounting and

Information

Management Division,

Washington, DC

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

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

Thomas H. Armstrong, Assistant General Counsel

Doreen S. Feldman, Assistant General Counsel

Jackie Goff, Senior Attorney

Amy M. Shimamura, Senior Attorney

Atlanta Regional

Office

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

(307333) Page 157 GAO/AIMD/RCED-95-134 Tennessee Valley Authority
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