DOE/EIA-0562(00)

Distribution Category UC-950

The Changing Structure of the

Electric Power Industry 2000: An Update

October 2000

Energy Information Administration

Office of Coal, Nuclear, Electric and Alternate Fuels

U.S. Department of Energy

Washington, DC 20585

This report was prepared by the Energy Information Administration, the independent statistical and

analytical agency within the Department of Energy. The information contained herein should not be

construed as advocating or reflecting any policy position of the Department of Energy or of any other

organization.
ii Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Contacts

This report was prepared by the staff of the Electric

Market Assessment Team, Electric Power Division,

Office of Coal, Nuclear, Electric and Alternate Fuels,

Energy Information Administration. Questions about

this publication, as well as other energy inquiries, may

be directed to the National Energy Information Center at

(202) 586-8800 or via Internet e-mail at

infoctr@eia.doe.gov. This report is accessible via the

Internet at http://www.eia.doe.gov/cneaf/electricity/

page/pubs.html.

General information regarding this publication may be

obtained from Robert M. Schnapp, Director, Electric

Power Division, by telephone at (202) 426-1211 or by

Internet at robert.schnapp@eia.doe.gov, or from Dr.

Suraj P. Kanhouwa, Chief, Electric Market Assessment

Team, by telephone at (202) 426-1257 or by Internet at

suraj.kanhouwa@eia.doe.gov. Specific questions

regarding the preparation and content of this report

should be directed to William D. Liggett, Project

Manager, by telephone at (202) 426-1139 or by Internet

at william.liggett@eia.doe.gov. 

Editing and production assistance for this report was

provided by Terry Varley, Sarah Loats, and Terri

Thigpen.

Questions regarding specific chapters of the report

should be directed as follows:

Chapter Author Telephone Internet

Chapter 1 William D. Liggett (202) 426-1139 william.liggett@eia.doe.gov

Chapter 2 Rebecca A. McNerney (202) 426-1251 rebecca.mcnerney@eia.doe.gov

Chapter 3 Rebecca A. McNerney (202) 426-1251 rebecca.mcnerney@eia.doe.gov

Chapter 4 Rebecca A. McNerney (202) 426-1251 rebecca.mcnerney@eia.doe.gov

Chapter 5 Ronald S. Hankey (202) 426-1188 ronald.hankey@eia.doe.gov

Chapter 6 Rebecca A. McNerney (202) 426-1251 rebecca.mcnerney@eia.doe.gov

Chapter 7 William D. Liggett (202) 426-1139 william.liggett@eia.doe.gov

Chapter 8 Ronald S. Hankey (202) 426-1188 ronald.hankey@eia.doe.gov

Chapter 9 William D. Liggett (202) 426-1139 william.liggett@eia.doe.gov
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update iii

Preface

Section 205(a)(2) of the Department of Energy Organization Act of 1977 (Public Law 95-91) requires the Administrator of the Energy Information Administration (EIA)

to carry out a central, comprehensive, and unified energy

data information program that will collect, evaluate,

assemble, analyze, and disseminate data and information

relevant to energy resources, reserves, production,

demand, technology, and related economic and statistical

information. To assist in meeting these responsibilities in

the area of electric power, EIA has prepared this report,

The Changing Structure of the Electric Power Industry 2000:

An Update. The purpose of this report is to provide a

comprehensive overview of the structure of the U.S.

electric power industry, focusing on the past 10 years,

with emphasis on the major changes that have occurred,

their causes, and their effects. It is intended for a wide

audience, including Congress, Federal and State agencies, the electric power industry, and the general public.

The legislation that created EIA vested the organization

with an element of statutory independence. EIA does

not take positions on policy questions. EIA's responsibility is to provide timely, high-quality information

and to perform objective, credible analyses in support of

deliberations by both public and private decision

makers. Accordingly, this report does not purport to

represent the policy positions of the U.S. Department of

Energy or the Administration.

This report can be accessed and downloaded as a

Portable Document Format (PDF) file from EIA’s web

site by connecting a web browser (i.e., Netscape, MS

Internet Explorer, etc.) to EIA’s Home Page at

http://www.eia.doe.gov. Once connected, click on

“Electric” to go to the “Electric Page.” Then, move to the

Publications menu and click on the publication title to

begin the download process.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update v

Contents

Page

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix

1. Introduction .............................................................................. 1

Part I: The U.S. Electric Power Industry as a Regulated Monopoly ...................................... 3

2. Historical Overview of the Electric Power Industry ............................................. 5

3. The U.S. Electric Power Industry Infrastructure: Functions and Components ....................... 9

Introduction ............................................................................ 9

Generation .............................................................................. 9

Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

The Components of Electricity Supply % Utilities and Nonutilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

4. The Federal Statutory Background of the Electric Power Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

The Public Utility Holding Company Act of 1935 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

The Public Utility Regulatory Policies Act of 1978 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

The Energy Policy Act of 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Part II: The U.S. Electric Power Industry in Transition to Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

5. Factors Underlying the Restructuring of the Electric Power Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Price Differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Technological Advances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

6. Federal Legislative Initiatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Major Issues Under Debate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

The Administration’s Comprehensive Electricity Competition Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . 52

7. Wholesale Power Markets and Restructuring the U.S. Power Transmission System . . . . . . . . . . . . . . . . 61

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

FERC Promotes Wholesale Competition and Transmission Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Status of Regional Transmission Organizations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Wholesale Electricity Trading Hubs and Power Exchanges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

Market Power In Wholesale Electricity Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

8. The Role of the States in Promoting Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

Case Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

9. Mergers, Acquisitions, and Power Plant Divestitures of Investor-Owned Electric Utilities . . . . . . . . . . 91
vi Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Contents (Continued) Page

Appendices

A. History of the U.S. Electric Power Industry, 1882-1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

B. Historical Chronology of Energy-Related Milestones, 1800-2000 (Not available electronically)

C. Pending Federal Restructuring Legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

D. Electric Power Industry Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

Tables

1. Percentage Change Between Various Electric Power Industry Statistics From The Great Depression 

Through World War II, 1932-1945 .............................................................. 7

2. Major Characteristics of U.S. Electric Utilities by Type of Ownership, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

3. Number of Electric Utilities by Class of Ownership and NERC Region, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . 18

4. Energy Supply Participants and Their Operations, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

5. Major Characteristics of U.S. Nonutilities by Type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

6. Relative Size of Registered Holding Companies as of December 31, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

7. Total Projected Additions of Electricity Generating Capability for Electric Generators by Technology Type,

1999-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

8. Proposed Legislation Influencing the Restructuring of the Electric Power Industry Introduced into the

106th Congress as of May 1, 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

9. Overview of The Federal Energy Regulatory Commission’s Efforts Promoting Competition in the

Electric Power Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

10. Companies Eligible to Sell Wholesale Power at Market-Based Rates, as of May 1, 2000 . . . . . . . . . . . . . . . . . 63

11. Major Provisions of FERC Order 888 on Open Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

12. Summary of Major Provisions of the Federal Energy Regulatory Commission’s Order 2000 Final Rule

Establishing Regional Transmission Organizations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

13. Selected Information on Independent System Operators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

14. Mergers and Acquisitions Between Investor-Owned Electric Utilities or Between Investor-Owned

Electric Utilities and Independent Power Producers, 1992 Through April 2000 . . . . . . . . . . . . . . . . . . . . . . . . 92

15. Comparison of the Number of Investor-Owned Electric Utilities Owning Generation Capacity,

1992 and 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

16. Selected Mergers and Acquisitions Involving Investor-Owned Electric Utilities and Natural Gas

Companies, 1997 Through April 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

17. Overview of Strategic Benefits of a Combined Electric and Natural Gas Company . . . . . . . . . . . . . . . . . . . . 102

18. Government Agencies Responsible for Reviewing Mergers and Acquisitions Involving Electric Utilities 104

19. Status of Power Generation Asset Divestitures by Investor-Owned Electric Utilities, as of April 2000 . . . . 105

B1. Historical Chronology of Energy-Related Milestones, 1800-2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

D1. Electric Power Industry Summary Statistics for the United States, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152

Figures

 1. Annual Statistics for the Total Electric Utility Industry, 1932-1980 ................................... 6

2. Electric Power Supply Functions ............................................................... 9

3. Prime Movers of Electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

4. Electric Power Industry Capability and Generation by Energy Source, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . 12

5. Energy Sources for Electricity Generation by Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

6. Transmission Ownership in the United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

7. The Main Interconnections of the U.S. Electric Power Grid and the 10 North American Electric Reliability

Council Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update vii

Figures (Continued) Page

8. Electric Control Area Operators % Continental United States, 1998. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

9. Service Areas for Investor-Owned Utilities, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

10. Service Areas of Federal Utilities, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

11. Publicly Owned Utilities in the United States, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

12. Service Areas of Cooperative Utilities, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

13. Shares of Nonutility Nameplate Capacity by Major Industry Group, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

14. Share of Utility and Nonutility Nameplate Capacity, Net Generation, Additions to Capacity, and Number

of Units by Ownership Category, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

15. Total Utility and Nonutility Nameplate Capacity, Net Generation, Additions to Capacity, and Number

of Units by Ownership Category, 1992-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

16. Annual Growth Rate of Utility and Nonutility Nameplate Capacity, Net Generation, Additions to

Capacity, and Number of Companies, 1992-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

17. Electric Utility Wholesale Power Purchases by Ownership Type, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

18. U.S. International Electricity Trade, 1985-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

19. Sales to Ultimate Consumers by Sector, 1992 and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

20. Share of Sales to Ultimate Consumers by Sector, 1992 and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

21. Sales to Ultimate Consumers by Class of Ownership, 1992 and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

22. Share of Sales to Ultimate Consumers by Class of Ownership, 1992 and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . 28

23. Status of State Electric Utility Deregulation Activity, as of July 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

24. Average Revenue per Kilowatthour for All Sectors by State, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

25. Average Revenue per Kilowatthour for the Industrial Sector by State, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

26. Relative Average Revenue of Electricity Sales: Ratio of Industrial Consumers to All Consumers,

1960-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

27. Independent System Operators and Regional Transmission Organizations in Operation or Under

Discussion as of April 1, 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

28. Major Wholesale Electricity Trading Hubs and Centralized Power Markets . . . . . . . . . . . . . . . . . . . . . . . . . . 79

29. Concentration of Ownership of Investor-Owned Utility Generating Capacity, 1992 and 2000 . . . . . . . . . . . . 98

30. Cumulative Electricity Generation Capacity Additions Through 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

31. Investor-Owned Electric Utility Generation Capacity Divested or to be Divested by Census Division,

as of April 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update ix

Executive Summary

The U.S. electric power industry, the last major regulated energy industry in the United States, is changing to

be more competitive. In some States, retail electricity

customers can now choose their electricity company.

New wholesale electricity trading markets, which were

previously nonexistent, are now operating in many

regions of the country. The number of independent

power producers and power marketers competing in

these new retail and wholesale power markets has

increased substantially over the past few years. To better

support a competitive industry, the power transmission

system is being reorganized from a balkanized system

with many transmission system operators, to one where

only a few organizations operate the system. However,

the introduction of these new markets has been far from

seamless. California, where retail competition was introduced in 1998, has had problems recently. Electricity

prices in some parts of the State have tripled and there

have been supply problems as well. Although not as

severe as California, New York’s electricity market has

had price spikes which may be attributable to problems

in the market design. While some observers argue that

deregulation should be scrapped, others argue that

deregulation is a noble endeavor and that these problems can be solved with structural adjustments to the

markets.

This reorganization is actually the second major

structural realignment in the history of the industry. The

first occurred during the late 1920s and early 1930s.

However, the changes then were mandated by a Federal

law that was designed to stop holding company

misconduct. Today, the changes that are occurring are

not driven by misconduct, but rather by economic and

technological factors. In fact, three primary catalysts are

driving the current movement toward a restructured

electric power industry. First is a general reevaluation of

regulated industries and a rethinking of how the

introduction of competition might improve efficiencies.

The telecommunications and banking industries have

been made more competitive, and the electric power

industry is being evaluated for similar efficiency gain

potential. The second factor driving the restructuring

debate is the wide disparity of electricity rates across the

United States (Figure ES1). In 1998, consumers in New

York paid more than two and one-half times the rates

that consumers in Kentucky paid for their electricity. In

the western United States, the rates paid by consumers

in California were well over twice the rates paid by

consumers in Washington. Technological improvements

in gas turbines have changed the economics of power

production. No longer is it necessary to build a 1,000-

megawatt generating plant to exploit economies of scale.

Combined-cycle gas turbines reach maximum efficiency

at 400 megawatts, while aero-derivative gas turbines can

be efficient at scales as small as 10 megawatts. These

improvements, involving less capital investment and

less time to build capacity, are the third set of catalysts

driving restructuring.

Because it provides the capability to move power over

long distances, the transmission system is an integral

component of the Nation’s electric power industry.

Through regulatory reform, the Federal Energy Regulatory Commission (FERC) has promoted the development of competitive wholesale power markets and

opening the transmission system to all qualified users.

Since the late 1980s, FERC has approved more than 850

applications to sell power competitively in wholesale

markets. In arguably its most ambitious effort to date, in

December 1999, FERC issued Order 2000 calling for

electric utilities to form regional transmission organizations (RTOs) that will operate, control, and possibly

own the Nation’s power transmission system. The

potential benefits of RTOs are the elimination of discriminatory behavior in using the transmission system,

improved operating efficiency, and increased reliability

of the power system.

A number of States have played an active role in promoting retail competition in the electric power industry.

Relatively high-cost States have been in the forefront of

enacting legislation or making rules to allow retail

competition. California and the northeastern States were

the first to allow retail competition and encourage

consumers to shop for their power suppliers. Other

States such as Kentucky and Idaho, whose rates are

among the lowest in the country, are not moving as

quickly. A recent report issued by Kentucky’s Special

Task Force on Electricity Restructuring found no

compelling reason for Kentucky to move quickly to

restructure its electric power industry. As of July 1, 2000,
x Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

MA

WA

4.03

4.90

5.16

5.76

4.80

4.02

5.95

6.07

5.43

6.26

5.70

5.30

6.08

5.71

6.28

6.04

5.44

5.34 6.38

10.17

9.83

11.93

9.59

10.30

5.78

5.78

5.62

5.98

4.16

5.56

5.07 5.88

5.53

6.45

6.99

6.88

6.40

7.01

OR

UT

MT

ID

CO

WY

4.31

ND

NE

KS

IA

MO

KY

WV

LA

SD

NV

AR

TX

FL

OK

MN

WI

IN OH

VA

MS AL

GA

SC

NC

TN

NH

VT

NJ

CT

RI

MD

IL DE

7.46

7.86

PA

MI

7.09

DC

7.41

7.33 6.78

AZ NM

CA

9.03

Cents per kWh

AK

9.97

HI

11.56

NY

10.71

ME 

9.75

U.S. Total Average Revenue per kWh in 1998 was 6.74 Cents

0-4.99

5.00-5.99

6.00-6.99

Over 7.00 

9.58

Figure ES1. Average Revenue per Kilowatthour for All Sectors by State, 1998

 kWh = Kilowatthour.

 Note: The average revenue per kilowatthour of electricity sold is calculated by dividing revenue by sales. Sales in deregulated

retail electricity markets are not included.

 Source: Energy Information Administration, Form EIA-861, “Annual Electric Utility Report.”

24 States and the District of Columbia had enacted

legislation or passed regulatory orders to restructure

the electric power industry (Figure ES2).

While most of the States have been active in restructuring their own jurisdictions, several bills designed to

provide a single Federal framework for wholesale and

retail competition have been introduced into the U.S.

Congress. These bills address myriad restructuring

issues such as reliability, reform of Federal power marketing administrations, a public benefits fund, tax

issues, and renewable energy portfolio standards.

Extensive hearings and debates have been held to

understand the interests and concerns of all parties

involved in the industry, and reaching consensus has

been an imposing pursuit. The recent price spikes in

California will certainly be a topic of discussion as the

restructuring debate moves forward. Retail prices in

San Diego have tripled in some cases over the summer

of 2000 and there have been blackouts in the San

Francisco Bay area. Any discussion surrounding new

bills will most certainly address mitigation of these

price spikes and supply curtailments. In all likelihood,

Congress will be involved in these activities for a

number of months before any comprehensive restructuring legislation will be passed. 

Mergers, acquisitions, and divestitures of power plants

have become widespread as investor-owned utilities

(IOUs) seek to improve their positions in the

increasingly competitive electric power industry. Since

1992, IOUs have been involved in 35 mergers, and an

additional 12 mergers are pending approval. One effect

of these mergers is that the size of IOUs is increasing.

In 1992, the 10 largest IOUs owned 36 percent of total

IOU-held generation capacity, and the 20 largest IOUs

owned 58 percent of IOU-held generation capacity. By

the end of 2000, the 10 largest IOUs will own an

estimated 51 percent of IOU-held generation capacity,

and the 20 largest will own approximately 72 percent.

While the size of the largest IOUs is increasing, because

of generation divestitures, they generally own a smaller

proportion of total generating capacity than in the

past.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update xi

Restructuring Legislation Enacted

Comprehensive Regulatory Order Issued

Commission or Legislative Investigation Ongoing

Legislation/Orders Pending

No Activity

Figure ES2. Status of State Electric Utility

Deregulation Activity, as of July

2000

In addition to mergers within the electricity industry,

IOUs&seeing growth opportunities in the natural gas

industry&are merging with or acquiring natural gas

companies, contributing to what is referred to as

convergence of the two industries. In the last 3 years,

23 convergence mergers have been completed or are

pending.

Influenced predominantly by State-level electricity

industry restructuring programs that emphasize the

unbundling of generation from transmission and distribution, and in some cases by a desire to exit the competitive power generation business, IOUs are divesting

power generation assets in unprecedented numbers.

Since late 1997, IOUs collectively have divested or are

in the process of divesting 156.5 gigawatts of power

generation capacity, representing about 22 percent of

total U.S. electric utility generation capacity. Divestiture means that the IOU will either sell its generation

capacity to another company or transfer the generation

capacity to an unregulated subsidiary within its own

holding company structure. As a result of mergers and

divestitures during the past few years, the organizational structure of the electric power industry (i.e.,

the numbers and roles of the industry participants)

is changing. The traditional role of the electric utility

as a provider of electric power is giving way to the

expanding role of nonutilities as providers of electric power. An analysis of electric power data collected

by the Energy Information Administration for the

period 1992 through 1998 offers the following insights:

  The number of IOUs has decreased by 8 percent

(261 in 1992 vs. 239 in 1998), while the number of

nonutilities generating electricity has increased by

9 percent (1,792 in 1992 vs. 1,954 in 1998).

  Nonutilities are expanding and buying utilitydivested generation assets, causing their net

generation to increase by 42 percent (286 million

megawatthours in 1992 vs. 406 million megawatthours in 1998) and their nameplate capacity to

increase by 73 percent (57 thousand megawatts in

1992 vs. 98 thousand megawatts in 1998). Nonutility capacity and generation will increase even

more as they acquire additional utility-divested

generation assets over the next few years.

  The nonutility share of net generation rose

from 9 percent (286 million megawatthours) in

1992 to 11 percent (406 million megawatthours) in

1998.

  Utilities have historically dominated the addition

of new capacity. However, utilities are adding

less capacity, while nonutility additions to capacity have been increasing at an average annual

rate of nearly 7 percent since 1992. In 1998 alone,

the nonutility share of additions to capacity was

82 percent (5,396 megawatts) with utilities adding

1,185 megawatts or 18 percent. 

Since 1998, it is expected that these trends have

continued.

 Source: Energy Information Administration.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 1

1. Introduction

Electric power generation in the United States is

changing from a regulated industry to a competitive

industry. Where power generation was once dominated

by vertically integrated investor-owned utilities (IOUs)

that owned most of the generation capacity, transmission, and distribution facilities, the electric power

industry now has many new companies that produce

and market wholesale and retail electric power. These

new companies are in direct competition with the

traditional electric utilities. Today, vertically integrated

IOUs still produce most of the country’s electrical

power, but that is changing. 

The long-standing traditional structure of the industry

was based, in part, on the economic theory that electric

power production and delivery were natural monopolies, and that large centralized power plants were the

most efficient and inexpensive means for producing

electric power and delivering it to customers. Large

power generating plants, integrated with transmission

and distribution systems, achieved economies of scale

and consequently lower operating costs than relatively

smaller plants could realize. Because of the monopoly

structure, Federal and State government regulations

were developed to control operating procedures, prices,

and entry to the industry in order to protect consumers

from potential monopolistic abuses. 

Several factors have caused this structure to shift to a

more competitive marketplace. First, technological

advances have altered the economics of power production. For example, new gas-fired combined cycle

power plants are more efficient and less costly than

older coal-fired power plants. Also, technological

advances in electricity transmission equipment have

made possible the economic transmission of power over

long distances so that customers can now be more

selective in choosing an electricity supplier. Second,

between 1975 and 1985, residential electricity prices and

industrial electricity prices rose 13 percent and 28

percent in real terms, respectively. These rate increases,

caused primarily by increases in utility construction and

fuel costs, caused Government officials to call into

question the existing regulatory environment. Third, the

effects of the Public Utilities Regulatory Policies Act of

1978, which encouraged the development of nonutility

power producers that used renewable energy to generate power, demonstrated that traditional vertically

integrated electric utilities were not the only source of

reliable power.

Competition in wholesale power sales received a boost

from the Energy Policy Act of 1992 (EPACT), which

expanded the Federal Energy Regulatory Commission’s

(FERC’s) authority to order vertically integrated IOUs to

allow nonutility power producers access to the transmission grid to sell power in an open market. FERC’s

authority to order access was implemented on a case-bycase basis and proved to be slow and cumbersome. To

remedy that, FERC issued Order 888 requiring all

vertically integrated IOUs to file an open access transmission tariff that would provide universal access to the

transmission grid to all qualified users. Order 888 was

an important stimulus in the development and

strengthening of competitive wholesale power markets,

but discriminatory practices regarding access to the

transmission grid still remained, and a more effective

effort was needed. In December 1999, FERC issued

Order 2000 calling for the creation of regional transmission organizations (RTOs), independent entities that

will control and operate the transmission grid free of any

discriminatory practices. Electric utilities are required to

submit proposals to form RTOs from October 2000

through January 2001.

In addition to wholesale competition, retail competition

has started in many States. For the first time in the

history of the industry, retail customers in some States

have been given a choice of electricity suppliers. As of

July 1, 2000, 24 States and the District of Columbia had

passed laws or regulatory orders to implement retail

competition, and more are expected to follow. The

introduction of wholesale and retail competition to the

electric power industry has produced and will continue

to produce significant changes to the industry. These

changes are referred to collectively as restructuring.

The purpose of this report is twofold. Part I (Chapters 2

through 4) can be used as a basic reference document for

information about the traditional electric power industry

before restructuring started, while Part II (Chapters 5

through 9) describes the major causes and events that

are changing the industry’s structure from a totally

regulated monopoly to one where both competition and
2 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

regulation coexist. Chapter 2 presents an overview of the

industry’s history from inception to approximately when

deregulation and restructuring started. Chapter 3

explains the infrastructure of the industry, detailing its

generating, transmitting, and distributing components.

It also presents industry-wide statistics depicting how

restructuring has changed the composition of the industry. For example, it illustrates the growing importance of nonutility power producers in meeting the

Nation’s electric power demands. Chapter 4 presents a

summary of 21 Federal acts that have directly or

indirectly affected the regulation, structure, and operating procedures of the electric power industry since its

inception. 

Chapter 5 presents a discussion of the causes

leading to Federal and State deregulation of power

generation and subsequently to restructuring of the

electric power industry. Following this, Chapter 6

discusses numerous Federal bills, either initiated in

Congress or by the Administration, designed to

promote, assign responsibility, or provide guidance

to continued deregulation of the industry. This

chapter also discusses the debate to repeal the Public

Utility Holding Company Act of 1935, and the

Public Utility Regulatory Policies Act of 1978, both

of which brought significant changes to the industry,

but are now considered by some to be obsolete in a

competitive electricity industry.

Continuing a discussion at the Federal level, Chapter 7

presents FERC’s role in promoting competitive wholesale electric power markets and restructuring the management, operation, and possibly the ownership of the

Nation’s high voltage bulk power transmission system.

Although the bulk power transmission system does not

receive wide public attention, it plays a key role in the

movement to a competitive industry.

Chapter 8 discusses the roles of individual States in promoting competition and restructuring at the retail level.

A summary of the status of each State’s restructuring

activities is presented along with discussions addressing

retail competition in five States. A discussion of the recent problems in the California market is included in this

chapter.

Chapter 9 examines IOUs&the largest component of the

electric industry in terms of power generation, value of

assets, and total revenues&and how they are coping

with and preparing for competition through mergers, acquisitions, and power plant divestitures. In many ways

these corporate activities, which transfer and/or consolidate ownership and control of the Nation’s electric

power assets, represent the core of industry restructuring. Readers will also find a discussion of the role of

the Federal Government in approving mergers and acquisitions, which has become more important as the

number of mergers increases.
Part I:

The U.S. Electric Power Industry

as a Regulated Monopoly
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 5

1 A vertically integrated utility is one which engages in generation, transmission, and distribution operations. 2 Energy Information Administration, Annual Outlook for U.S. Electric Power 1985, DOE/EIA-0474(85) (Washington, DC, August 1985),

p. 3.3 The Clayton Antitrust Act of 1914 strengthened the Sherman Antitrust Act of 1890. 4 This form of rate setting has been blamed by some groups for removing the incentive for utilities to achieve maximum efficiency in

operations and planning, thereby exhibiting the major flaw in this type of regulation and promoting the push for its demise. 5 A holding company is a company that confines its activities to owning stock in and supervising management of other companies.

The Securities and Exchange Commission, as administrator of the Public Utility Holding Company Act of 1935, defines a holding company

as “a company which directly or indirectly owns, controls or holds 10 percent or more of the outstanding voting securities of a public utility

company” (15 USC 79b, par. A (7)). 6 Energy Information Administration, Annual Outlook for U.S. Electric Power 1985, DOE/EIA-0474(85) (Washington, DC, August 1985),

p. 3.7 Encyclopedia Americana, International Edition, Vol. 22 (New York, NY: Americana Corporation, 1977), p. 769. 8 In October 1977, many of the regulatory powers of the FPC were transferred to the Federal Energy Regulatory Commission (FERC).

2. Historical Overview of the Electric Power Industry

At the beginning of the 20th century, vertically integrated1

 electric utilities produced approximately twofifths of the Nation's electricity. At that time, many

businesses (nonutilities) generated their own electricity.

When utilities began to install larger and more efficient

generators and more transmission lines, the associated

increase in convenience and economical service

prompted many industrial consumers to shift to the

utilities for their electricity needs. With the introduction

of the electric motor came the inevitable development

and use of more home appliances. Consumption of

electricity skyrocketed along with the utility share of the

Nation's generation.

Utilities operated in designated exclusive franchise areas

which, in the early years, were usually municipalities.

Along with the service area designation came the

obligation to serve all consumers within that territory.

“The growth of utility service territories . . . brought

State regulation of privately owned electric utilities in

the early 1900s. Georgia, New York, and Wisconsin

established State public service commissions in 1907,

followed shortly by more than 20 other States. Basic

State powers included the authority to franchise the

utilities; to regulate their rates, financing, and service;

and to establish utility accounting systems.”2

The early structure of the electric utility industry was

predicated on the concept that a central source of power

supplied by efficient, low-cost utility generation, transmission, and distribution was a natural monopoly.

Because monopolies in the United States were outlawed

by the Sherman Antitrust Act,3

 regulation of the utilities

was a necessity. In addition to its intrinsic design to

protect consumers, regulation generally provided reliability and a fair rate of return to the utility. The result

was traditional rate-based regulation.4

Electric utility holding companies5

 were forming and

expanding during the early 1900s, and by the 1920s they

controlled much of the industry. By 1921, privately

owned utilities were providing 94 percent of total generation, and publicly owned utilities contributed only 6

percent.6

 At their peak in the late 1920s, the 16 largest

electric power holding companies controlled more than

75 percent of all U.S. generation.7

 Originally formed to

reap the benefits (mostly of a financial nature) of centralized ownership of a multitude of subsidiaries, these

unregulated holding companies were in a position to

abuse their power over their subsidiaries. Sometimes,

the result was increased prices paid by consumers of

electricity. Because the States could not regulate an

interstate holding company, it became apparent that the

Federal Government would have to step in. After

several large holding company systems collapsed, an

investigation by the Federal Trade Commission was

ordered, leading eventually to the passage of the Public

Utility Holding Company Act of 1935 (PUHCA). Under

the provisions of the Act, holding companies became

regulated by the Securities and Exchange Commission.

Under Title II of PUHCA utilities involved in interstate

wholesale marketing or transmission of electric power

became regulated by the Federal Power Commission

(FPC).8
6 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

9 For further details, refer to the subsequent section on The Public Utility Holding Company Act of 1935.

Genera tion in Billions

Of K ilowa tthours

E n erg y Sa les in B illio n s

Of K ilowa tthours

Total Installed Capacity

(Nam eplate) in Hundred s

Of M egaw atts

Total Revenue From 

Sales in M illions of 

Dollars

20,000

50,000

100 ,000

500

200

5 0

100

1,000

2,000

5,000

10,000

1932 1936 1940 1944 1948 1952 1956 1960 1964 1968 1976 1980 

YEAR 

Figure 1. Annual Statistics for the Total Electric 

Utility Industry, 1932-1980

On October 29, 1929, the U.S. stock market crashed,

creating losses of $16 billion for that month&a staggering

amount of money in 1929&and leading to the Great

Depression. The social and economic well-being of the

Nation was severely shaken, but the electric power

industry was able to stay adrift of the devastation, and

local operating utilities remained solvent. Figure 1

shows that, although the rate of growth in the industry

did wane at times during the Depression, the U.S. electric utility industry’s capacity, generation, revenues, and

sales experienced a healthy growth pattern from 1932

through 1980. Table 1 shows the percentage change

between various electric power industry statistics for the

years 1932 and 1945, which also demonstrates the robust

condition of the industry during that time.

In the years immediately following the onset of the Great

Depression, Congress took actions designed to alleviate

some of the most acute problems, e.g., unemployment

and the plight of farmers. Two of these actions directly

and advantageously affected the electric power industry:

the development of Federally owned power and the

creation of the Rural Electrification Administration

(REA). (See inset on page 7.) 

During the 1920s and the early years of the Depression,

the public became disenchanted with privately owned

power and began to support the idea of Government

ownership of utilities, particularly hydroelectric power

facilities. This disenchantment was chiefly the result of

abuses heaped on utilities, and ultimately on their

customers, by holding companies,9

 causing the price of

electricity to increase. Government-owned hydroelectric

power facilities could produce power cheaply and sell it

to publicly owned utilities for distribution. This concept

was a controversial political issue at the time, with

strong arguments on both sides. Many believed that private power did not employ fair operating practices and,

therefore, Government-owned power was wholeheartedly supported. Others were opposed to the Government entering the electricity business because they

believed that the Government was exploiting hydroelectric sites. Nevertheless, the Federal Government did

become heavily involved through the construction and

ownership of several massive hydroelectric facilities.

During the presidency of Franklin D. Roosevelt (1933 to

1945), a number of these facilities were built and publicly

owned power took a strong hold. President Roosevelt

began his New Deal campaign, which was designed to

help the American public by providing jobs, and

ultimately hope, during the long years of the

Depression. As part of the program, he proposed that

the Government build four hydropower projects and,

within a year after his proposal, his administration

began to implement the projects. Large Bureau of

Reclamation dams began serving the western States: 

  Hoover Dam began generation in 1936, followed

by other large projects. 

  Grand Coulee, the Nation’s largest hydroelectric

dam, began operation in 1941. 

  The U.S. Army Corps of Engineers flood control

dams provided additional low-priced power for

preferred customers.

Under the Tennessee Valley Authority Act of 1933, the

Federal Government supplied electric power to States,

counties, municipalities, and nonprofit cooperatives,

soon including those of the REA. The Bonneville Project

Act of 1937 pioneered the Federal power marketing

administrations. By 1940, Federal power pricing policy

was set; all Federal power was marketed at the lowest

possible price, while still covering costs. From 1933 to

1941, one-half of all new capacity was provided by

Federal and other public power installations. By the end

 Source: Electric Utility Systems Engineering Department of

the General Electric Company, Electric Utility Systems and

Practices, ed. Homer M. Rustebakke, 4th ed., Chapter 1, “The

Electric Utility Industry” (New York, NY: Wiley & Sons, Inc.,

1983), p. 4.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 7

10 Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970, pp. 2, 24.

Table 1. Percentage Change Between Various Electric Power Industry Statistics From the Great

Depression Through World War II, 1932-1945

 1932 1945 Percent Change

Real GNP (1958 dollars in billions) . . . . . . . . . . . . . . . . . . . 154 437 184

Energy consumption (Btu trillions) ................... 18,022 36,030 100

Electricity production (kWh millions) .................. 99,359 271,255 173

Real prices (1958 dollars):

 Electricity (cents/kWh) .......................... 7.08 2.89 -59

 Oil (dollars per barrel) ........................... 2.16 2.04 -6

 Coal (dollars per ton) ........................... 3.25 5.15 58

Percent electricity produced by:

 Privately-owned utilities .......................... 75.0 66.7 %

 Publicly-(Government)owned utilities . . . . . . . . . . . . . . . . 4.9 15.3 %

 Industry and transport ........................... 20.1 18.0 %

Production per kW of capacity (kilowatthours) .......... 2,309 4,440 92

Coal equivalent per kWh produced (pounds) . . . . . . . . . . . 1.5 1.3 -3

Return earned on average capital (percent) . . . . . . . . . . . . 6.3 6.6 5

Return earned on average equity (percent) . . . . . . . . . . . . 7.9 8.2 4

Bond yields (percent) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.7 2.6 -45

Utility stock index (S&P electric) ..................... 16.64 14.94 -10

Industrial stock index (S&P 400) .................... 5.37 14.72 174

 Source: L. S. Hyman, America's Electric Utilities, Past, Present and Future, Fifth Edition, Public Utilities Reports, Inc. (Arlington,

VA, August 1994), p. 113.

of 1941, public power contributed 12 percent of total

utility generation, with Federal power alone contributing

almost 7 percent.10 Besides electric power, these dams

provided flood control, navigation, area development,

and greatly needed work for the unemployed. Even

during the Eisenhower Administration's policy of no

new starts, Federal power continued to grow as earlier

projects came on line.

In the mid-1930s, many homes, farms, and ranches in

rural areas were still without lights, indoor bathrooms,

refrigerators, or running water. It was too expensive

The Rural Electrification Administration

In an effort to lessen the effects of the Depression on the American farmer, in 1936 “Congress passed the Norris-Rayburn Act,

the purpose of which was to ensure a 10-year integrated program for electrifying American farms. To that end, it authorized

appropriations of $410 million.”a

 The Federal Government encouraged the growth of rural electricity service by subsidizing the

formation of rural electric cooperatives. The Rural Electrification Act of 1936 established the Rural Electrification Administration

(REA). Congress authorized it as an independent Federal bureau, and in 1939 it was reorganized as a division of the U.S.

Department of Agriculture. The REA undertook a program to provide rural areas and towns with populations under 2,500 with

inexpensive electric lighting and power. “To implement those goals, the administration made long-term, self-liquidating loans

to State and local governments, to farmers’ cooperatives, and to nonprofit organizations; no loans were made directly to the

consumers.”b

 REA-backed cooperatives enjoyed Federal power preference plus lower property assessments, exemptions from

Federal and State income taxes, and exemption from State and Federal Power Commission regulation.c

 aM. L. Cooke, Electrifying the Countryside, http://newdeal.feri.org/tva/cooke.htm.

 b

Rural Electrification Administration, http://www.infoplease.com/ce5/CE045037.html.

 c

 The Rural Electrification Administration has been replaced by the Rural Utilities Service, whose mission is to improve the

quality of life in rural America by administering its Electrification, Telecommunications, and Water and Waste Disposal

Programs.
8 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

11 The Federal Government moved quickly in the mid-1930s to, where opportunities appeared, produce and distribute less expensive

federally produced electricity to preference customers. 12 U.S. Bureau of the Census, Historical Statistics of the United States, Colonial Times to 1970, Bicentennial Edition, Part 2 (Washington,

DC, 1975), p. 827. 13 Energy Information Administration, Annual Outlook for U.S. Electric Power 1985, DOE/EIA-0474(85) (Washington, DC, August 1985),

p. 7.14 A nonutility is a corporation, person, agency, authority, or other legal entity or instrumentality that owns electric generating capacity

and is not an electric utility. Nonutility power producers include qualifying cogenerators, qualifying small power producers, and other

nonutility generators (including independent power producers) without a designated franchise service area, and which do not file forms

listed in the Code of Federal Regulations, Title 18, Part 141.

for the investor-owned utilities that served the cities to

stretch their lines into the countryside, so many areas

remained without access to electric power. The Federal

Government encouraged the growth of rural electricity

service by subsidizing the formation of rural electric

cooperatives. The Rural Electrification Act of 1936

established the REA to provide loans and assistance to

organizations providing electricity to rural areas and

towns with populations under 2,500. REA-backed

cooperatives enjoyed Federal power preferences11 plus

lower property assessments, exemptions from Federal

and State income taxes, and exemption from State and

Federal Power Commission regulation. As a result, by

1941 the proportion of electrified farm homes rose to 35

percent, more than three times that of 1932.12

For decades, utilities were able to meet the increasing

demand for electricity at decreasing prices. Economies

of scale were achieved through capacity additions,

technological advances, and declining costs. Of course,

the monopolistic environment in which they operated

left them virtually unhindered by the worries that

would have been created by competitors. This overall

trend continued until the late 1960s, when the electric

utility industry saw decreasing unit costs and rapid

growth give way to increasing unit costs and slower

growth.13 Over a relatively short time, a number of

events took place which contributed to the unprecedented reversal in the growth and well-being of the

industry: the Northeast Blackout of 1965 raised

pressing concerns about reliability; the passage of the

Clean Air Act of 1970 and its amendments in 1977

required utilities to reduce polluting emissions; the Oil

Embargo of 1973-1974 resulted in burdensome

increases in fossil-fuel prices; the accident at Three Mile

Island in 1979 led to higher costs, regulatory delays,

and greater uncertainty in the nuclear industry; and

inflation (in general) caused interest rates to more than

triple.

While the industry was attempting to recover from this

onslaught of damaging events, Congress designed

legislation that would reduce U.S. dependence on

foreign oil, develop renewable and alternative energy

sources, sustain economic growth, and encourage the

efficient use of fossil fuels. One result was the passage

of the Public Utility Regulatory Policies Act of 1978

(PURPA). PURPA became a catalyst for competition in

the electricity supply industry, because it allowed

nonutility facilities14 that met certain ownership, operating, and efficiency criteria established by FERC to

enter the wholesale market. Utilities initially did not

welcome this forced competition, but some soon found

that buying generation from a qualifying facility (QF)

had certain advantages over adding to their own

capacity, especially because of the increasing

uncertainty of recovering capital costs. The growth of

nonutilities was further advanced by the Energy Policy

Act of 1992 (EPACT). EPACT expanded nonutility

markets by creating a new category of power producers&exempt wholesale generators (EWGs)&that are

exempt from PUHCA's corporate and geographic restrictions. Like QFs, EWGs are wholesale producers

that do not sell electricity in the retail market and do

not own transmission facilities. Moreover, unlike the

nonutilities that qualified under PURPA, EWGs are not

regulated and may charge market-based rates, and

utilities are not required to buy their power. The

growth of EWGs marked another step toward

increasing the level of competition in the wholesale

electricity market. (For a more detailed description of

the purpose and effects of PUHCA, PURPA, and

EPACT, see Chapter 4.)

Prior to passage of PURPA in 1979, the electric power

industry had been relatively stable for approximately

45 years. Today, however, the industry is undergoing

immense change, both structurally and operationally.

Having a basic knowledge of how it was originally

organized can facilitate understanding its current transitional state. A more detailed account of the industry’s

history is provided in Appendix A, History of the U.S.

Electric Power Industry, 1882-1991. Appendix B,

Historical Chronology of Energy-Related Milestones,

1800-2000, lists the major technological and institutional events in the development of the U.S. electric

power industry. The following chapter describes its

organizational components.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 9

15 Electric utilities are defined as either privately owned companies or publicly owned agencies that engage in the supply (including

generation, transmission, and/or distribution) of electric power. Nonutilities are privately owned companies that generate power for their

own use and/or for sale to utilities and others. The next section of this chapter delineates the types and characteristics of utilities and

nonutilities as well as their changing roles in the supply of the Nation’s electricity. 16 The demand for power varies over the day, with about 16 hours of “on-peak” time in the day and about 8 hours of “off-peak” time

during the night. Demand for electric power typically reaches its highest peak on very hot or very cold days. At those times, many of the

available plants in a region may need to be brought online to meet the high demand.

Generatio n of Distribu tion

electricity

Transm ission

Figure 2. Electric Power Supply Functions

3. The U.S. Electric Power Industry Infrastructure:

Functions and Components

Introduction

The transition of the U.S. electric power industry from a

regulated monopoly to a deregulated industry where

generators of electricity compete for customers is in full

swing. Consequently, many aspects of the industry are

changing, including its infrastructure. This chapter

explains the functions and components (or participants)

contained in the infrastructure and uses data collected

by the Energy Information Administration (EIA) to

reflect the changes that have taken place in the past

decade or so. Shifts in the number and ownership of

power production facilities, the volume of power generation and capacity, and other areas are also explained.

The fundamental structure of the industry has been

based on the vertical integration of utilities, i.e., their

involvement in the three functions of power supply.

Those functions are generation, transmission, and distribution of electricity (Figure 2). Generation is defined as

the production of electric energy from other energy

sources. Transmission is the delivery of electric energy

over high-voltage lines from the power plants to the

distribution areas. Distribution includes the local system

of lower voltage lines, substations, and transformers

which are used to deliver the electricity to end-use

consumers. Prior to detailing the components of power

supply along with their characteristics, this chapter will

outline the three functions of power supply.

Generation

Generation facilities are currently owned and operated

by two categories of companies&utilities and nonutilities.15 Electric power generators use a variety of

prime movers and energy sources to generate electric

energy. Prime movers are the engine, turbine, water

wheel, or similar machines that drive an electric generator. Energy sources include combustion of fossil

fuels, nuclear fission, kinetic energy in water or wind,

chemical energy in a fuel cell, and sunlight. Wind, water,

sunlight, geothermal energy, biomass, and waste

products are renewable energy sources that are considered inexhaustible.

Generating units vary in size. Nuclear and fossil-fuel

steam-electric units typically have large capacities with

many over 1,000 megawatts (MW), while hydroelectric

dams range from less than 1MW to thousands of MW at

some of the large Federal dams. Gas turbines, combustion turbines, and combined-cycle units are typically

less than 200 MW, but some are larger. Wind and solar

plants are relatively small. Distributed generation, which

can be installed at or near the customer’s site can be

quite small, such as rooftop photovoltaic arrays or fuel

cells ranging from several to a few hundred kilowatts.

The generating units operated by an electric utility vary

by intended usage, that is, by the three major types of

load (generally categorized as base, intermediate, and

peak) requirements the utility must meet.16 A base-load

generating unit is normally used to satisfy all or part of

the minimum or base load of the system and, as a

consequence, produces electricity at an essentially

constant rate and runs continuously. Base-load units are

generally the largest of the three types of units, but they
10 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

17 Thermal efficiency is a measure generally expressed in Btu per kilowatthour which is computed by dividing the total Btu content of

the fuel burned for electric generation by the resulting net kilowatthour generation. 18 Capability is the maximum load that a generating unit, generating station, or other electrical apparatus can carry under specified

conditions for a given period of time without exceeding approved limits of temperature and stress.

cannot be brought on line or taken off line quickly. Peakload generating units can be brought on line quickly and

are used to meet requirements during the periods of

greatest or peak load on the system. They are normally

smaller plants using gas and combustion turbines. Intermediate-load generating units meet system requirements

that are greater than base-load but less than peak load.

Intermediate-load units are used during the transition

between base-load and peak-load requirements.

Types of Generators

Steam Units: Steam-electric (thermal) generating units

are typically the large baseload plants. Steam produced

in a boiler turns a turbine to drive an electric generator

(Figure 3a). Fossil fuels (coal, petroleum and petroleum

products, natural gas or other gaseous fuels) and other

combustible fuels, such as biomass and waste products,

are burned in a boiler to produce the steam. Nuclear

plants use nuclear fission as the heat source to make

steam. Geothermal or solar thermal energy also produce

steam. The thermal efficiency17 of fossil-fueled steamelectric plants is about 33 to 35 percent. The waste heat

is emitted from the plant either directly into the

atmosphere, through a cooling tower, or sent to a lake

for cooling. A water pump brings the residual water

from the condenser back to the boiler.

Gas Units: Gas turbines and combustion engines use the

hot gas from burning fossil fuels, rather than steam, to

turn a turbine that drives the generator. These plants can

be brought up quickly, and so are used as peaking

plants. The number of gas turbines is growing as technological advances in gas turbine design and declining

gas prices have made the gas turbine competitive with

the large steam-electric plants. However, thermal

efficiency is slightly less than that of the large steamelectric plants (Figure 3b). The gas wastes are disposed

of through an exhaust stack.

Combined-Cycle Units: Combined cycle plants first use

gas turbines to generate power and then use the waste

heat in a steam-electric generator to produce more

electricity. Thus, combined-cycle plants make more

efficient use of the heat energy in fossil fuels. New technology is improving the thermal efficiency of combinedcycle plants, with some reports of 50 to 60 percent

thermal efficiency (Figure 3c). 

Cogenerating Units: Cogenerators, also known as combined heat and power generators, are facilities that

utilize heat for electricity generation and for another

form of useful thermal energy (steam or hot water), for

manufacturing processes or central heating. There are

two types of cogeneration systems: bottom-cycling and

top-cycling. In a bottom-cycling configuration, a manufacturing process uses high temperature steam first and

a waste-heat recovery boiler recaptures the unused

energy and uses it to drive a steam turbine generator to

produce electricity. In one of two top-cycling configurations, a boiler produces steam to drive a turbinegenerator to produce electricity, and steam leaving the

turbine is used in thermal applications such as space

heating or food preparation. In another top-cycling

configuration, a combustion turbine or diesel engine

burns fuel to spin a shaft connected to a generator to

produce electricity, and the waste heat from the burning

fuel is recaptured in a waste-heat recovery boiler for use

in direct heating or producing steam for thermal

applications (Figure 3d). 

Other Units: The kinetic energy in moving water and

wind is used to turn turbines at hydroelectric plants and

wind facilities to produce electricity. Other types of

energy conversion include photovoltaic (solar) panels

that convert light energy directly to electrical energy,

and fuel cells that convert chemical energy directly to

electrical energy. 

Energy Sources

Coal: Coal is the Nation’s primary fuel for electricity

generation, representing 40 percent of the capability,18

and producing over half (52 percent) of the generation

(Figure 4) because coal is used as a baseload fuel. 

Gas and Petroleum: Gas and petroleum units, which are

typically used for peak demand, make up 23 percent and

8 percent, respectively, of generating capability. In 1998,

petroleum-fired generation provided 4 percent of our

electricity, while gas-fired units provided 15 percent. 

Coal, petroleum, and gas are considered fossil-fuels and

collectively produced 71 percent of the Nation’s electricity in 1998. When fossil fuels are burned in the

production of electricity, a variety of gases and particulates are formed. If these gases and particulates are
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 11

19 Hydroelectric power includes pumped storage which is the generation of electric energy during peak-load periods by using water

previously pumped into an elevated storage reservoir during off-peak periods when excess generating capacity is available to do so. When

additional generating capacity is needed, the water can be released from the reservoir through a conduit to turbine generators located in

a power plant at a lower level. 

Steam

Boiler

Turbine 

Gas flam e

Feed water

pump

Condenser

Heat from 

condenser 

sent to lake or 

cooling tow er.

3c. Schematic of combined cycle

Shaft

Alternator

Turbine 

Alternator

Shaft

Steam

Boiler

Steam Flow

Turbine 

Shaft

Alternator

Furnace

Feed water

pump

Condenser

Heat from condenser used in 

factory for process heat.

3d. Cogeneration schematic

Steam

Boiler

Steam Flow

Turbine 

Shaft

Alternator

Furnace

Feed water

pump

Condenser

Heat from 

condenser 

sent to lake or 

cooling tow er.

3a. Schematic of generic thermal generator

Hot gas

Turbine 

Shaft

Alternator

Gas flam e

3b. Schematic of gas turbine

To stack

Figure 3. Prime Movers of Electricity

not captured by some pollution control equipment, they

are released into the atmosphere. Among the gases

emitted during the burning of fossil fuels are sulfur

dioxide (SO2), nitrogen oxides (NOx), and carbon dioxide

(CO2). Coal-fired generating units produce more SO2,

NOx, and CO2 than other fossil-fuel units for two

reasons. First, because coal generally contains more

sulfur than other fossil fuels, it creates more SO2 when

burned. Second, there are more emissions from coalfired plants because more coal-fired capacity than other

fossil-fueled capacity is in use.

Nuclear: Nuclear power plants, which also are used as

baseload plants, represented 13 percent of the generating

capability, and generated 19 percent of electricity in

1998. Nuclear plants have increased their capacity

factors (the ratio of electricity actually produced to

potential production if the unit runs at full power)

steadily in recent years, reaching a record high of

86 percent in 1999. 

Hydroelectric: Hydroelectric capability19 accounts for 13

percent of the Nation’s generating capability. Precipitation patterns affect the availability of hydroelectric

power, which contributed 9 percent of net generation in

1998, a relatively dry year.

 Source: R. Baldick, “Introduction to Electric Power Systems for Legal and Regulatory Professionals,” Course Materials, The

University of Texas at Austin (1999).
12 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Figure 5. Energy Sources for Electricity

Generation by Region

Coal

40%

Renewables

and Other

3%

Hydro (Conventional and 

Pumped Storage)

13%

Nuclear

13%

Petroleum

8%

Gas

23%

Million megawatthours

Coal

Petroleum

Gas

Nuclear

Hydro

Renewables

and Other

0

500

1,000

1,500

2,000 52%

4%

15%

19%

9%

1%

Coal

Natural Gas

Petroleum

Nuclear

Hydroelectric

Figure 4. Electric Power Industry Capability and Generation by Energy Source, 1998

Renewables: Renewable generating units use energy

sources that are judged to be inexhaustible including

solar, wind, geothermal, municipal solid waste, and biomass fuels such as landfill methane gas, wood

byproducts, and waste. (Hydroelectric power is also

considered a renewable resource.) Many wind and solar

plants are intermittent in nature, depending on the

availability of their energy source. In 1998, renewables

other than hydropower represented 3 percent of capacity and 1 percent of generation, as they are typically

used only intermittently.

Regional Variation

The type of energy source used for generating electricity

varies in the United States by region and is usually

dictated by the availability of natural resources (Figure

5). The Pacific Northwest generates most of its power at

large hydroelectric projects owned by the Federal

Government. The Nation’s coal-producing States and

regions are the location of the majority of coal-fired

plants, and consequently the source of much of the air

emissions resulting from the combustion of coal. Ohio,

West Virginia, Kentucky, and Tennessee are the largest

users of coal for electricity generation in the Nation.

Texas, Louisiana, and Oklahoma are rich in natural gas,

and make use of it for electricity generation. Much of the

Nation’s petroleum-fired generation is concentrated in

Florida and New York.

 Note: The large icons on this map represent about 10 GW

of capacity, not individual plants, in a regional area for each

fuel source. Smaller icons represent about 5 GW capacity.

Where less than 5 GW of capacity for a fuel type exists for an

individual region or State, generating plants are not

represented on this map.

 Source: Form EIA-860A, “Annual Electric Generator Report

% Utility” and Form EIA-860B, “Annual Electric Generator

Report % Nonutility.”

 Source: Capacity: Form EIA-860A, “Annual Electric Generator Report-Utility” and Form EIA-860B, “Annual Electric Generator

Report % Nonutility.” Generation: Form EIA-860B, “Annual Electric Generation Report % Nonutility” and Form EIA-759, “Monthly

Power Plant Report.”

Electric Power Industry

Net Generation

(3,620 million megawatthours)

Net Summer Capability

(776 thousand megawatts)
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 13

20 Refer to Table 2 for a definition of the types of utilities and other entities involved in electricity supply.

California’s tight restrictions on air emissions discourage

coal-fired generation. Natural gas, which burns more

cleanly than coal, is used by many California plants for

electricity generation. However, California utilities purchase electricity from outside of the State, some of which

is generated from coal as the main fuel source. The

energy source available for electricity generation is a

factor in the disparity of retail prices across the Nation.

For example, the Northwest enjoys the low cost of

hydropower, while some Northeast States depend

heavily on petroleum and nuclear power.

Regulation of Generation

The foundation for strong Federal involvement in the

electricity industry was established in the early 1900s.

The electric power industry became recognized as a

natural monopoly due to its production of a product

most efficiently provided in a specific location by one

supplier. Because monopolies in the United States were

outlawed by the Sherman Antitrust Act, regulation of

the utilities was a necessity. Interstate wholesale markets

and transmission became regulated by the Federal

Power Commission. In 1997, regulatory authority was

given to the Federal Energy Regulatory Commission

(FERC). Today, FERC has jurisdiction over interstate

movement of electricity by private utilities (investorowned utilities), power marketers, power pools, power

exchanges, and independent system operators (ISOs).

FERC approves rates for wholesale sales of electricity

and reviews rates set by the Federal Power Marketing

Administrations (PMAs). FERC also confers Exempt

Wholesale Generator status (a classification of generator

created by the Energy Policy Act of 1992 (EPACT)) and

certifies qualifying small power producers and

cogeneration facilities under provisions of PURPA. An

additional responsibility of FERC is licensing the

construction and operation of hydroelectric power

projects and enforcing the provisions of the licenses. 

The State Public Utility Commissions (PUCs) have jurisdiction over intrastate trade of electricity. The PUCs

regulate retail rates for customers, approve sites for

generation facilities, and issue State environmental

regulations. 

The Environmental Protection Agency (EPA) is charged

with implementing the provisions of Title IV of the

Clean Air Act. The EPA establishes rules requiring

fossil-fueled power plants to reduce the air emissions

and pollutants that are a primary cause of acid rain,

sulfur dioxide, and nitrogen oxides. Carbon dioxide

(CO2) emissions are tracked, but no regulations exist at

this time for CO2 emissions. 

The Nuclear Regulatory Commission licenses the construction and operation of nuclear power plants and fuel

cycle facilities, inspects licensed nuclear facilities and

oversees decommissioning, and enforces the provisions

of nuclear licenses.

Transmission

Electric power transmission is the transportation of large

blocks of power over relatively long distances from a

central generating station to main substations close to

major load centers or from one central station to another

for load sharing. The transmission grid consists of high

voltage (between 138 and 765 kilovolts) overhead and

underground conducting lines made of either copper or

aluminum. High-voltage transmission lines are used

because they require less surface area for a given

carrying power capacity, and result in less line loss.

Because of resistance in the conductors, some power is

“lost” as dissipated heat during transmission. At the

generating station, the voltage of the three-phase alternating current output from the generator is increased to

the required transmission voltage by a step-up transformer. The high-voltage alternating current is then

transmitted through the transmission grid to the load

center where it is again transformed (stepped down) to

lower voltages required by distribution lines.

In the United States, investor-owned utilities (IOUs)

own 73 percent of the transmission lines, Federally

owned utilities own 13 percent, and public utilities and

cooperative utilities own 14 percent (Figure 6).20 Not all

utilities own transmission lines (i.e., they are not vertically integrated), and no independent power producers

or power marketers own transmission lines. Over the

years, these transmission lines have evolved into three

major networks (power grids), which also include

smaller groupings or power pools. The major networks

consist of extra-high-voltage connections between individual utilities designed to permit the transfer of

electrical energy from one part of the network to

another. These transfers are restricted, on occasion,

because of a lack of contractual arrangements or because

of inadequate transmission capability. The three networks are the Eastern Interconnect, the Western

Interconnect, and the Texas Interconnect (Figure 7). The
14 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Investor-O wned

Utilities

73%

Cooperative Utilities

6% Publicly Owned 

Utilities

8%

Federally 

Owned 

Utilities

13% e Estimated High-Voltage Transmission Line Miles in th

United States, 1994 (Miles)

Investor-Owned 199,924

Publicly Owned 21,960

Cooperative 16,005

Federally Owned 35,675

Total 273,564

Figure 6. Transmission Ownership in the United

States

MAPP

MAIN

NPCC

SERC

MAAC

SPP

ECAR

FRCC

ERCOT

WSCC

ERCOT

Texas Interconnect

Western

Interconnect

Eastern

Interconnect

Figure 7. The Main Interconnections of the U.S.

Electric Power Grid and the 10 North

American Electric Reliability Council

Regions

ECAR - East Central Area Reliability Coordination Agreement

ERCOT - Electric Reliability Council of Texas

FRCC - Florida Reliability Coordinating Council

MAAC - Mid-Atlantic Area Council

MAIN - Mid-America Interconnected Network

MAPP - Mid-Continent Area Power Pool

NPCC - Northeast Power Coordinating Council

SERC - Southeastern Electric Reliability Council

SPP - Southwest Power Pool

WSCC - Western Systems Coordinating Council

 Note: The Alaska Systems Coordinating Council (ASCC) is

an affiliate NERC member.

 Source: North American Electric Reliability Council.

Source: Calculations made by the Energy Information

Administration, Office of Coal, Nuclear, Electric, and Alternate

Fuels, from data taken from FERC Form 1, “Annual Report of

Major Electric Utilities, Licensees, and Others.” (Data for

cooperative utilities are for 1997.)

The Texas Interconnect is not interconnected with the

other two networks (except by certain direct current

lines). The other two networks have limited interconnections to each other. Both the Western and the

Texas Interconnect are linked with different parts of

Mexico. The Eastern and Western Interconnects are

completely integrated with most of Canada or have links

to the Quebec Province power grid. Virtually all U.S.

utilities are interconnected with at least one other utility

by these three major grids. The exceptions are utilities in

Alaska and Hawaii. The interconnected utilities within

each power grid coordinate operations and buy and sell

power among themselves. 

Regulation of Transmission

Under authority of the Federal Power Act of 1935, as

amended, FERC exercises principal regulatory authority

over the transmission system. Under this authority,

FERC: 

  regulates wholesale electricity rates and services

for wholesale transactions 

  approves sale or leasing of transmission facilities

  approves mergers and acquisitions between

IOUs, and 

  exercises jurisdiction over the interstate commerce of electricity.

FERC’s authority covers about 73 percent of the power

transmission system in the United States, while the

remaining 27 percent is Federally owned, municipally

owned, or owned by cooperative utilities, and is not

under FERC’s jurisdiction.

In 1965, a major blackout in the Northeastern United

States precipitated the voluntary formation of the North

American Electric Reliability Council (NERC). NERC is

responsible for overall reliability, planning, and coordination of the electricity supply in North America. The

membership of NERC is unique&as a not-for-profit

corporation, NERC's owners comprise 10 Regional

Councils (Figure 7). The members of these Regional

Councils come from all segments of the electric

industry%utilities, independent power producers, power

marketers, and electricity customers. The councils cover

the 48 contiguous States, part of Alaska, and portions of

Canada and Mexico. The councils are responsible for

overall coordination of bulk power policies that affect

the reliability and adequacy of service in their areas.

They also regularly exchange operating and planning

information among their member utilities. However,

participation in NERC is voluntary and participants in

the industry are neither required to be a member nor to
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 15

21 Competition for the distribution of electricity is being evaluated in California.

22 Distributed generators are indirectly connected to the grid through their consumers’ facilities which are connected for backup

purposes or to sell excess power.

Figure 8. Electric Control Area Operators %

Continental United States, 1998

follow the directions of NERC. The boundaries of the

NERC regions follow the service areas of the electric

utilities in the region, many of which do not follow

States boundaries.

Because electric energy is instantaneously generated and

consumed, the operation of an electric power system

requires a coordinated balancing of generation and

consumption of power. Control Area Operators (CAOs)

perform this function, as well as other important tasks,

that allow the interconnected electric power systems and

their components to operate together both reliably and

efficiently. There are approximately 150 Control Areas

in the Nation (Figure 8). Most are run by the dominant

large investor-owned utility in a geographic area defined

by an interconnected transmission grid and power plant

system. The CAOs dispatch generators from a central

control center with computerized systems in such a way

as to balance supply and demand and maintain the

transmission system safely and reliably.

Distribution

Distribution is the delivery of electric power from the

transmission system to the end-use consumer. The distribution systems begin at the substations, where power

transmitted on high voltage transmission lines is

transformed to lower voltages for delivery over low

voltage lines to the consumer sites. The system ends at

the consumers’ meters. Distribution is considered a

“natural monopoly” and is likely to remain a regulated

function because duplicate systems of lines would be

impractical and costly.21

Distributed generation is a growing part of the restructured electric power industry. Distributed generation is

defined as small generators located near or at the

consumer site, within the distribution system. Distributed generators are not directly connected to the

transmission grid.22 The amount of distributed

generation is expected to increase in the future, with the

technological and economic improvements in small

generators. Fuel cells and photovoltaic systems are

becoming more available as alternative or supplemental

power sources. 

Net metering arrangements are increasingly being

offered in some States to consumers that install distributed generation units using renewable resources at their

homes or businesses. The owners may use all or most of

the power produced, but at times the distributed generator produces more power than the owner uses, and

excess power flows out onto the distribution system. The

consumer’s meter “runs backwards,” and “nets out” the

portion of the electricity delivered to the consumer. 

Regulation of Distribution and Retail Sales

The distribution of electric power is an intrastate function under the jurisdiction of State public utility commissions (PUCs). Under the traditional regulatory

system, the PUCs set the retail rates for electricity, based

on the cost of service, which includes the costs of

distribution. Retail rates are set by the PUC in

ratemaking rulings. The rates include the cost to the

utility for generated and purchased power, the capital

costs of power, transmission, and distribution plants, all

operations and maintenance expenses, and the costs to

provide programs often mandated by the PUC for

consumer protections and energy efficiency, as well as

taxes. As the industry restructures, in some States the

PUC will eventually no longer regulate the retail rates

for generated or purchased power. Retail electricity

prices will be open to the market forces of competition.

The PUCs will continue to regulate the rates for distribution of power to the consumer. They also have a say

in the siting of distribution lines, substations, and

generators. Metering and billing are under jurisdiction

of the PUC and in some States are becoming competitive

functions. As the industry restructures, the PUCs’

responsibilities are changing. The goal of each State PUC

 Source: Energy Information Administration, Office of Coal,

Nuclear, Electric and Alternate Fuels. Based on data contained

in Form EIA-861, “Annual Electric Utility Report.”
16 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

23 Nonutilities generate but do not transmit or distribute electricity.

24 As earlier stated, EPACT provided a Federal mandate to open up the national electricity transmission system to wholesale suppliers,

marking the beginning of competition in the electric power industry, and was the impetus for significant structural changes. In 1996, the

Federal Energy Regulatory Commission (FERC) issued its Order 888, which carried out the goal of EPACT. From the 1970s until 1992, little

change had occurred in the industry, either structurally or operationally, with the exception of the creation of nonutility qualifying facilities

brought about by PURPA.

remains to provide their State’s consumers with reliable,

reasonably and fairly priced electric power.

The Components of Electricity

Supply % Utilities and Nonutilities

Introduction

This section provides a basic understanding of the infrastructure of the electric power industry, i.e., the

components that carry out the generation, transmission,

and distribution of electricity. The components consist of

two broad categories of energy providers&utilities and

nonutilities.23 Their ownership characteristics, their current role in electricity supply, and how some roles have

shifted since passage of the Energy Policy Act of 1992

(EPACT)24 are explained in the following sections. In

most cases, the data presented are for 1998, although in

some cases, data for earlier years are compared with

1998 data to show changes.

Utilities

Electric utilities in general are defined as either privately

owned companies or public agencies engaged in the

generation, transmission, and/or distribution of electric

power for public use. Utilities can be further classified

into four subcategories based on ownership&investorowned, Federally owned, other publicly owned, and

cooperatively owned (Tables 2 and 3).

Under the traditional system, utilities are given a

monopoly franchise over a specific geographic area. In

return for this franchise, the electric utility is regulated

by State and Federal agencies. Some electric utilities

have service territories extending beyond a single county

or parish. Others just serve a municipality or part of

a county. Many counties in the United States are served

by more than a single utility, and some parts of the

country (such as Kossuth County, Iowa and Fillmore

County, Minnesota) have more than 10 electric utilities

operating in a county.

To move electricity among utilities, an extensive system

of high-voltage transmission lines is owned and operated by the Nation's larger utilities. This transmission

network permits electricity trading between utilities. 

Without transmission facilities, electricity could not be

moved from power plants to the thousands of distribution systems serving millions of consumers of electric

power.

Utilities can also be categorized in a different manner,

i.e., the number of companies that generate, transmit,

and/or distribute electric power. It is interesting to note

that only about 27 percent of the Nation's 3,169 utilities

actually generate electric power. Many electric utilities

(67 percent) are exclusively distribution utilities, purchasing wholesale power from others to distribute it,

over their own distribution lines, to the ultimate consumer. These are primarily the utilities owned by State

and local governments and cooperatives. Conversely, all

nonutilities generate power but do not own or operate

transmission or distribution systems (Table 4).

Investor-Owned Utilities

Two basic organizational forms exist among investor-owned utilities (IOUs). The most prevalent is the

individual corporation. Another common form is the

holding company, in which a parent company is established to own one or more operating utility companies

that are integrated with one another. 

Most of the IOUs sell power at retail rates to several

different classes of consumers and at wholesale rates to

other utilities, including other investor-owned, Federal,

State, and local government utilities, public utility

districts, and rural electric cooperatives (Figure 9). They

also have high-density service areas.

Federal Utilities

There are nine Federal electric utilities in the United

States (Figure 10). They include four operating entities:

the Department of Defense's U.S. Army Corps of Engineers (USACE), the Department of the Interior's U.S.

Bureau of Reclamation, the Department of the Interior's

U.S. Bureau of Indian Affairs (USBR), and the Department of State's International Water and Boundary

Commission. These entities operate the Federal hydroelectric plants.

Also included in this category are four Federal power

marketing administrations (PMAs): the Bonneville
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 17

Ownership Major Characteristics

Investor-Owned Utilities (IOUs)

IOUs account for about three-quarters of

all utility generation and capacity. There

are 239 IOUs in the United States, and

they operate in all States except

Nebraska. They are also referred to as

privately owned utilities.

 Earn a return for investors; either distribute their profits to stockholders as

dividends or reinvest the profits.

 Are granted service monopolies in specified geographic areas.

 Have obligation to serve and to provide reliable electric power.

 Are regulated by State and Federal governments, which in turn approve rates

that allow a fair rate of return on investment.

 Most are operating companies that provide basic services for generation,

transmission, and distribution.

Federally Owned Utilities

There are 9 Federally owned utilities in

the United States, and they operate in all

areas except the Northeast, the upper

Midwest, and Hawaii.

 Power not generated for profit.

 Publicly owned utilities, cooperatives, and other nonprofit entities are given

preference in purchasing from them.

 Primarily producers and wholesalers.

 Producing agencies for some are the U.S. Army Corps of Engineers, the U.S.

Bureau of Reclamation, and the International Water and Boundary Commission.

 Electricity generated by these agencies is marketed by Federal power

marketing administrations in the U.S. Department of Energy .

 The Tennessee Valley Authority is the largest producer of electricity in this

category and markets at both wholesale and retail levels.

Other Publicly Owned Utilities

Other publicly owned utilities include:

 Municipals

 Public Power Districts

 State Authorities

 Irrigation Districts

 Other State Organizations

There are 2,009 in the United States.

 Are nonprofit State and local government agencies.

 Serve at cost; return excess funds to the consumers in the form of community

contributions and reduced rates.

 Most municipals just distribute power, although some large ones produce and

transmit electricity; they are financed from municipal treasuries and revenue

bonds.

 Public power districts and projects are concentrated in Nebraska, Washington,

Oregon, Arizona, and California; voters in a public power district elect

commissioners or directors to govern the district independent of any municipal

government.

 Irrigation districts may have still other forms of organization (e.g., in the Salt

River Project Agricultural Improvement and Power District in Arizona, votes for

the Board of Directors are apportioned according to the size of landholdings).

 State authorities, such as the New York Power Authority and the South Carolina

Public Service Authority, are agents of their respective State governments.

Cooperatively Owned Utilities

There are 912 cooperatively owned

utilities in the United States, and they

operate in all States except Connecticut,

Hawaii, Rhode Island, and the District of

Columbia.

 Owned by members (rural farmers and communities).

 Provide service mostly to members.

 Incorporated under State law and directed by an elected board of directors

which, in turn, selects a manager.

 The Rural Utilities Service (formerly the Rural Electrification Administration) in

the U.S. Department of Agriculture was established under the Rural

Electrification Act of 1936 with the purpose of extending credit to co-ops to

provide electric service to small rural communities (usually fewer than 1,500

consumers) and farms where it was relatively expensive to provide service.

Power Marketers

There are 194 active power marketers in

the United States.

 Some are utility-affiliated while others are independent.

 Buy and sell electricity.

 Do not own or operate generation, transmission, or distribution facilities.

 Source: Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels.

Table 2. Major Characteristics of U.S. Electric Utilities by Type of Ownership, 1998
18 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Table 3. Number of Electric Utilities by Class of Ownership and NERC Region, 1998

NERC Regiona InvestorOwned Federal

State,

Municipal,

and Other

Government Cooperative Total

ECAR . . . . . . . . . . . . . . . . . 43 0 228 103 374

ERCOT . . . . . . . . . . . . . . . . 6 0 66 58 130

FRCC . . . . . . . . . . . . . . . . . 3 0 31 12 46

MAAC . . . . . . . . . . . . . . . . . 18 0 49 19 86

MAIN . . . . . . . . . . . . . . . . . . 17 0 131 33 181

MAPP . . . . . . . . . . . . . . . . . 14 0 486 171 671

NPCC . . . . . . . . . . . . . . . . . 58 0 127 10 195

SERC . . . . . . . . . . . . . . . . . 20 2 352 262 636

SPP . . . . . . . . . . . . . . . . . . . 11 0 250 86 347

WSCC . . . . . . . . . . . . . . . . . 27 7 253 137 424

 Subtotal NERC 217 9 1973 891 3090

Alaskab . . . . . . . . . . . . . . . . 19 0 36 21 76

Hawaiib ................ 3 0 0 0 3

 U.S. Total ............. 239 9 2,009 912 3,169

 a

NERC is the North American Electric Reliability Council, formed in 1968 by the electric utility industry to promote the reliability

and adequacy of bulk power supply in the electric utility systems of North America.

 b

Alaska and Hawaii are not full members of NERC.

 Note: See Figure 7 for a map of NERC regions. 

 Source: Energy Information Administration, Form EIA-861, “Annual Electric Utility Report.”

Power Administration, the Western Area Power Administration, the Southwestern Power Administration, and

the Southeastern Power Administration (Figure 10).

These Federal utilities exist to market and sell the power

produced at Federal hydroelectric projects. They also

purchase energy for resale from other electric utilities in

the United States and Canada.

The ninth Federal utility is the Tennessee Valley

Authority (TVA), the largest Federal power producer,

which operates its own power plants and sells the power

in the Tennessee Valley region in both the wholesale and

retail markets. The TVA generates electricity from coal,

gas, oil, and nuclear power as well as hydropower. 

Of the Federal utilities, three are considered major

producers of electricity: the TVA, the USACE, and the

USBR. Generation by the USACE, except for the North

Central Division (Saint Mary's Falls at Sault Ste. Marie,

Michigan) and by the USBR, is marketed by the four

PMAs.

Consumers of Federal power are usually large industrial

consumers or Federal installations. Most of the remaining energy generated by non-profit Federal utilities

is sold in the wholesale market to publicly owned

utilities and rural cooperatives for resale at cost. These

wholesale consumers have preference claims to Federal

electricity. Only the surplus remaining after meeting the

energy requirements of preference consumers is sold to

investor-owned utilities. 

Other Publicly Owned Utilities 

Publicly owned electric utilities can be categorized as

generators and nongenerators. (In contrast, virtually all

investor-owned electric utilities own and operate generating capacity.) Generators are those electric utilities that

own and operate generating capacity to supply some or

all of their customers’ needs. However, some generators

supplement their production by purchasing power. The

nongenerators rely exclusively on power purchases.

Their primary function is to distribute electricity to their

consumers. The nongenerators comprise over half of the

total number of publicly owned electric utilities. 

Other publicly owned utilities include municipal

authorities, State authorities, public power districts, irrigation districts, and other State organizations. Municipal

utilities tend to be concentrated in cities where the loads

are small. They exist in every State except Hawaii, but

most are located in the Midwest and Southeast. State

authorities are utilities that function in a manner similar

to Federal utilities. They generate or purchase electricity
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 19

Table 4. Energy Supply Participants and Their Operations, 1998

Participants/Operations Number of Companies Percent of All Utilities

Vertically Integrated (Generate,a

 Transmit,b and Distributec)

 Utilities Only

 Investor Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140 4.4

 Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 0.1

 Publicly Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132 4.2

 Cooperatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 0.6

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295 9.3

Generate and Transmit Only

 Utilities Only

 Investor Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 0.3

 Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 0.1

 Publicly Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 1.1

 Cooperatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 1.3

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89 2.8

Transmit and Distribute Only

 Utilities Only

 Investor Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 0.2

 Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0.0

 Publicly Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 1.8

 Cooperatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 2.3

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139 4.4

Generate and Distribute Only

 Utilities Only

 Investor Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 0.8

 Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0.1

 Publicly Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 403 12.7

 Cooperatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 0.7

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 453 14.3

Generate Only

 Utilities

 Investor Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 0.3

 Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 --

 Publicly Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 0.4

 Cooperatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0.0

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 0.8

 Nonutilities ........................................ 1,930 d

100.0

Transmit Only

 Utilities Only

 Investor Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 0.2

 Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 --

 Publicly Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 0.3

 Cooperatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 0.6

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 1.1

 See notes at end of table.
Table 4. Energy Supply Participants and Their Operations, 1998 (Continued)

Participants/Operations Number of Companies Percent of All Utilities

20 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Figure 9. Service Areas of Investor-Owned

Utilities, 1998

Tennessee Valley

Authority

USCE-Detroit Dist.

Mission Valley Power

Southwestern

Power

Admin.

USBIA-San Carlos

Bonneville

Power 

Admin.

Western Area

Power Admin.

Southeastern

Power Admin.

Figure 10. Service Areas of Federal Utilities, 1998

Distribute Only

 Utilities Only

 Investor Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 1.1

 Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0.0

 Publicly Owned .................................. 1,358 42.8

 Cooperatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 735 23.2

 Total ......................................... 2,128 67.1

Othere

 Utilities Only

 Investor Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 0.2

 Publicly Owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0.1

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 0.2

 Power Marketersf .................................. g

400 %%

a

An electricity generator is a facility that converts mechanical energy into electrical energy. 

b

An electricity transmitter moves or transfers electric energy over an interconnected group of lines and associated equipment

between points of supply and points at which it is transformed for delivery to consumers or is delivered to other electric systems.

Transmission is considered to end when the energy is transformed for distribution to the consumer. c

An electricity distributor delivers electric energy to an end user.

 d

This figure represents the percentage of nonutilities rather than utilities.

e

“Other” includes maintenance service companies for parent utilities that perform such functions as guard services, equipment

maintenance, etc. Also, one of the publicly owned utilities in this category acts as an agent to buy and schedule power for the parent

utility. f

An electricity power marketer buys and sells electricity but does not own or operate generation, transmission, or distribution

facilities.

g

In 1998, about 400 power marketers filed rate tariffs with FERC, of which 111 reported wholesale sales and 49 reported retail

sales. Currently, over 850 power marketers have filed rate tariffs with FERC.

 -- = Not applicable.

 Sources: Energy Information Administration, Form EIA-861, “Annual Electric Utility Report,” and Form EIA-860B, “Annual Electric

Generator Report % Nonutility.”

 Source: Resource Data International, 1998.

 Source: EIA, Office of Coal, Nuclear, Electric and Alternate

Fuels. Based on data contained in Form EIA-412, “Annual

Report of Public Electric Utilities.”
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 21

25 Form EIA-861, “Annual Electric Utility Report,” 1998.

Figure 11. Publicly Owned Utilities in the United

States, 1998

Figure 12. Service Areas of Cooperative Utilities,

1998

 Source: EIA, Office of Coal, Nuclear, Electric and Alternative

Fuels. Based on data contained in Form EIA-412, “Annual

Report of Public Electric Utilities.”

 Source: National Rural Electric Cooperative Association’s

website at http://www.nreca.org (1998).

from other utilities and market large quantities in the

wholesale market to groups of utilities within their

States at lower prices than the individual utilities would

otherwise pay. Large concentrations of publicly owned

power districts are in the Midwest and Eastern regions

of the United States (Figure 11). In general, publicly

owned utilities tend to have lower costs than

investor-owned utilities because they often have access

to tax-free financing and do not pay certain taxes or dividends. They also tend to have high-density service areas.

Rural Electric Cooperatives

Most rural electric cooperative utilities are formed and

owned by groups of residents in rural areas to supply

power to those areas (Figure 12). Some cooperatives may

be owned by a number of other cooperatives. There are

really three types of cooperatives: (1) distribution only,

(2) distribution with power supply, and (3) generation

and transmission. Cooperatives currently operate in 47

States, and they represent 29 percent of the total number

of utilities in the country. Most distribution cooperatives

resemble municipal utilities in that they often do not

generate electricity, but purchase it from other utilities.

The other type (generating and transmission cooperatives) are usually referred to as “power supply

cooperatives.” These cooperatives are usually owned by

the distribution cooperatives to whom they supply

wholesale power. Distribution cooperatives resemble

Federal utilities, supplying electricity to other utility

consumers from their generating capability.

Non-Federal Power Marketers

The introduction of the competitive wholesale market

for electricity has brought about a fifth subcategory of

electric utilities&power marketers. They are classified as

electric utilities because they buy and sell electricity at

the wholesale and retail levels. However, they do not

own or operate generation, transmission, or distribution

facilities, and therefore, their data (primarily electricity

purchase and sales data) are not included in this chapter.

Although relatively small in terms of volume of sales,

the power marketers are a growing segment of the

industry. Currently, over 850 power marketers have

filed rate tariffs with FERC to sell electric power, but

only approximately 160 were actively engaged in retail

and/or wholesale sales during 1998.25

Nonutilities

Nonutilities are privately owned entities that generate

power for their own use and/or for sale to utilities and

others. Nonutilities can be classified in two distinct

ways. One approach separates nonutilities into separate

categories based on their classification by FERC and the

type of technology they employ: (1) cogenerators and

(2) small power producers, both of which are qualifying

facilities (QFs) because they meet certain criteria set
22 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

26 QFs receive certain benefits under PURPA. In particular, they are guaranteed that electric utilities will purchase their output at a price

based on the utility's “avoided cost.”

Table 5. Major Characteristics of U.S. Nonutilities by Type

Type Major Characteristics

Cogenerators (QF)

(Combined Heat and Power)

 Are qualified under PURPA by meeting certain ownership, operating, and

efficiency criteria established by FERC.

 Sequentially produce electric energy and another form of energy, such as

heat or steam, using the same fuel source.

 Are guaranteed that utilities will purchase their output at a price based on

the utility's “avoided cost” and will provide backup service at

nondiscriminatory rates.

Small Power Producers (QF)  Are qualified under PURPA by meeting certain ownership, operating, and

efficiency criteria, established by FERC.

 Use biomass, waste, renewable resources (water, wind, solar), or

geothermal as a primary energy source.

 Fossil fuels can be used but renewable resources must provide at least 75

percent of the total energy input.

 Are guaranteed that utilities will purchase their output at a price based on

the utility's “avoided cost” and will provide backup service at

nondiscriminatory rates.

Exempt Wholesale Generators  Creation authorized by EPACT.

 Are exempt from PUHCA's corporate and geographic restrictions.

 Are wholesale producers; do not sell retail.

 Do not possess significant transmission facilities.

 Utilities are not required to purchase their electricity.

 Are regulated but usually may charge market-based rates.

Cogenerators (Non-QF)  Are not qualified under the provisions of PURPA.

 Are nonutilities, utilizing a cogenerating technology, which may themselves

consume part of the electricity they cogenerate.

Noncogenerators

(Non-QF)

 Are not qualified under the provisions of PURPA.

 Do not utilize a cogenerating technology.

 QF = Qualifying facility (under PURPA).

 Note: An entity can be any combination of cogenerator QF, small power producer QF, and exempt wholesale generator.

 Source: Energy Information Administration, Electric Power Annual 1995, Volume II, DOE/EIA-0348(95)/2 (Washington, DC,

December 1996).

forth by PURPA;26 (3) exempt wholesale generators

mandated by EPACT and designated by FERC,

(4) cogenerators not qualified under PURPA, and

(5) noncogenerators not qualified under PURPA (Table

5). As the industry furthers its transition to full retail

competition in the generation portion of electricity

supply, the distinctions between the nonutility subcategories are becoming less clear, and some may fade

entirely within the next 10 years as a result of ongoing

structural changes and the possible repeal of the Federal

mandates that created them.

A second approach for classifying nonutilities is based

on the major industry group into which the nonutility

company falls. Nonutility electricity generators are

found in many different industries. In 1998, most

nonutility generating capacity (52 percent) was in the

manufacturing sector of the economy (Figure 13). Within

the manufacturing sector, the chemical industry, the

paper industry, and the petroleum refining industry

account for 70 percent of the electricity generated by that

sector. The manufacturing processes conducted at many

of these plants can utilize the thermal energy produced

when cogenerating electricity. After manufacturing, the

largest portion of nonutility electricity generating capacity (23 percent) can be found in the electric, gas, and

sanitary services sector. The entities that make up this

sector are primarily engaged in producing, transporting,
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 23

27 EIA defines nameplate capacity as the maximum design production capacity specified by the manufacturer of a processing unit or

the maximum amount of a product that can be produced running the manufacturing unit at full capacity. 28 EIA defines net generation as gross generation minus plant use from all electric utility-owned plants.

29 Energy Information Administration, Electric Power Annual 1998, Volume I, DOE/EIA-0348(98)/1 (Washington, DC, April 1999),

p. 1.

Chemical 33%

Paper 24%

Petroleum 

 Refining 13%

Other

 Manufacturing 30%

Manufacturing

52 %

Mining 3%

Other 21%

Electric,

Gas, and

Sanitary 

Services 23%

Total Nonutility Capacity in 

Manufacturing

51.3 Gigawatts

Total Nonutility Capacity

98.1 Gigawatts

Figure 13. Shares of Nonutility Nameplate

Capacity by Major Industry Group,

1998

Note: Totals may not equal the sum of components due

to independent rounding.

Source: Energy Information Administration, Form EIA860B, “Annual Electric Generator Report % Nonutility.”

and/or distributing electricity, although they may be

engaged in steam, gas, water, and/or waste disposal

services as a primary business. Unlike nonutilities in

other sectors, these nonutilities are engaged primarily in

activities similar to the generation activities carried out

by electric utilities. The remaining nonutility capacity is

found either in the mining industry (3 percent) or in

various other industries, including agriculture, transportation, and other services (21 percent).

A Comparison of Utility and Nonutility Roles

The relative contribution of utility and nonutility components to the supply of the Nation’s electricity can be

understood by looking at their shares of nameplate

capacity,27 net generation,28 additions to capacity, and

number of companies (Figure 14). The number of publicly owned utilities (i.e., those owned by State and local

governments) far outweighs the number of IOUs (2,009

versus 239); however, in 1998 IOUs were responsible for

the lion’s share of capacity (66 percent) and generation

(68 percent). On the other hand, the nonutility share of

capacity and generation has been relatively small, but

that trend is changing. The change began with the

passage of PURPA when nonutilities were promoted as

energy-efficient, environment-friendly alternative

sources of electricity. More recently, FERC Order 888

opened the bulk power transmission grid to suppliers

other than utilities. In response, nonutilities have been

expanding their roles in wholesale power supply and are

taking advantage of the divestiture activities of utilities

by purchasing their generation assets. As a result, the

nonutility share of total industry capacity rose from 7

percent in 1992 to 12 percent in 1998.29

A yearly comparison of the above-mentioned four statistics (Figure 15) gives a clear picture of the significant

shifts in ownership of electricity supply that have taken

place in the relatively short period of time since passage

of EPACT. A number of these shifts can be attributed to

the strategic business plans companies are using to cope

in a deregulated and competitive market. For instance,

since 1992, the number of IOUs has decreased by 8 percent and their nameplate capacity has decreased by

5 percent (Figure 16). The decrease in the number of

IOUs is a result of recent mergers between IOUs. The

decrease in generation capacity is evidence of the

divestiture of generation assets. On the other hand, the

fact that IOU net generation has actually increased by

11 percent since 1992 can be attributed to such factors as

higher demand for electricity and efficiency gains

stemming from competition and mergers.

Although the number of nonutility companies decreased

in 1997, the number of nonutilities grew by 9 percent

during the 7-year period examined. Also, with nonutilities expanding by buying IOU generation assets and

constructing new generation units, the result was an

increase in nonutility nameplate capacity (up 73 percent

since 1992) and generation (up 42 percent since 1992).

Nonutility additions to capacity have been increasing at

an average annual rate of nearly 7 percent since 1992.

Electricity Sales and Trade

Wholesale Sales and Trade

The bulk power system outlined earlier makes it possible

for utilities to engage in wholesale (for resale) electric

power trade. Wholesale trade has historically played an

important role, allowing utilities to reduce power costs,

increase power supply options, and improve reliability.

In quantity, it accounts for more than one-half of

electricity sales to ultimate consumers. Since 1986, the

total amount of wholesale power trade (as measured by

purchased power plus exchange received) among utilities and nonutilities has grown at an average annual rate
24 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

IOUs

68.1%

Federals

7.6%

Publics

9.1%

Co-ops

4.0%

Nonutilities

11.2%

Net Generation

(3,620 Million Megawatthours)

67.8% 68.1%

IOUs

Federals 4.7%

0.2%

Publics

39.4%

Co-ops

17.9%

Nonutilities

37.9%

Number of Companies

(5,100)

IOUs

4.7%

a

IOUs

66.2%

Federals

8.2%

Publics

10.7%

Co-ops

3.1%

Nonutilities

11.9%

Nameplate Capacity

(826 Thousand Megawatts)

66.1%

IOUs 11.0%

Federal 0.1% Publics 3.8%

Co-ops 3.5%

Nonutilites 81.6%

Capacity Additions

(6,581 Megawatts)

Co-ops 3.5%

Publics 3.8%

Federals 0.1%

Figure 14. Share of Utility and Nonutility Nameplate Capacity, Net Generation, Additions to Capacity, and

Number of Units by Ownership Category, 1998

of 4.7 percent, which is more than the rate of growth for

retail sales by utilities (3.1 percent). In the past, wholesale trade has been dominated by utility purchases from

other utilities. In 1998, utilities purchased a total of 1,669

billion kilowatthours of wholesale electricity from other

utilities and a smaller but increasing amount (259 billion

kilowatthours) from nonutility producers (Figure 17).

Wholesale power sales by nonutilities to utilities and

wheeling (the transmission of power from one point to

another via a third party) by utilities have both grown

vigorously. Wholesale sales by nonutilities grew from 40

billion to 259 billion kilowatthours between 1986 and

1998, yielding an average annual growth rate of 16.8

percent. Wheeling, while not increasing as spectacularly,

grew at an annual average rate of 8.3 percent over the

same period. Utility sales to ultimate consumers,

wholesale sales by nonutilities, and wheeling by utilities

all grew more slowly between 1990 and 1998, with

annual growth rates of 2.2 percent, 12.6 percent, and 4.3

percent, respectively.

International Trade

In recent years, U.S. international trade in electricity has

returned to the levels of the mid-1980s (Figure 18). U.S.

trade is mostly in imports, which were more than three

times the level of exports in 1998. Most imports are from

Canada (99 percent of total gross imports in 1998) and

the remainder is from Mexico.

 a Data for power marketers are not included.

 Sources: Energy Information Administration, Form EIA-759, “Monthly Power Plant Report,” Form EIA-860A, “Annual Electric

Generator Report % Utility,” Form EIA-861, “Annual Electric Utility Report,” and Form EIA-860B, “Annual Electric Generator Report %

Nonutility.”
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 25

30 Refer to Figure 7 for details on NERC regions.

1992 1993 1994 1995 1996 1997 1998

0

50

100

150

200

250

Thousand Megawatts

Cooperative

Federal

Publicly Owned Nonutility

1992 1993 1994 1995 1996 1997 1998

300

400

500

600

700

Thousand Megawatts

0

Investor-Owned

Nameplate Capacity

1992 1993 1994 1995 1996 1997 1998

0

200

400

600

800

Million Megawatthours

Cooperative

Federal

Nonutility

Publicly Owned

1992 1993 1994 1995 1996 1997 1998 1,000

1,500

2,000

2,500

3,000

Million Megawatthours

0

Investor-Owned

Net Generation

1992 1993 1994 1995 1996 1997 1998

0

800

1,600

2,400

3,200

4,000

4,800

5,600

6,400

Megawatts

Cooperative

Federal

Nonutility

Investor-Owned

Publicly Owned

Additions to Capacity

1992 1993 1994 1995 1996 1997 1998

0

500

1,000

1,500

2,000

2,500

Number of Companies

Cooperative

Federal

Nonutility

Investor-Owned

Publicly Owned

Number of Companiesa

Figure 15. Total Utility and Nonutility Nameplate Capacity, Net Generation, Additions to Capacity, and

Number of Units by Ownership Category, 1992-1998

Imported power is particularly important to the NPCC

and MAPP regions of NERC,30 where gross imports

were 7.2 and 6.5 percent, respectively, of retail sales by

utilities in these regions in 1998. In contrast, gross

imports for the Nation as a whole that year were 1.2 percent of retail sales by utilities.

Retail Sales by Sector

Electricity is sold to four classes or sectors of retail (i.e.,

ultimate) consumers&residential, commercial, industrial,

and “other.” The residential sector includes private

households and apartment buildings where energy is

consumed primarily for space heating, water heating, air

conditioning, lighting, refrigeration, cooking, and clothes

drying appliances. The commercial sector includes nonmanufacturing business establishments such as hotels,

motels, restaurants, wholesale businesses, retail stores,

and health, social, and educational institutions. The

industrial sector includes manufacturing, construction,

mining, agriculture, fishing, and forestry establishments.

The “other” sector includes public street and highway

 a Data for power marketers are not included.

 Sources: Energy Information Administration, Form EIA-759, “Monthly Power Plant Report,” Form EIA-860, “Annual Electric

Generator Report,” Form EIA-860A, “Annual Electric Generator Report % Utility,” Form EIA-861, “Annual Electric Utility Report,”

Form EIA 867, “Annual Nonutility Power Producer Report,” and Form EIA-860B, “Annual Electric Generator Report % Nonutility.”
26 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

31 There are some exceptions to the types of customers listed in each of the four sectors. For instance, some small manufacturers are

classified as commercial while some large commercial establishments are classified as industrial.

1992 1993 1994 1995 1996 1997 1998

0

5

10

15

20

25

30

35

-5

-10

Percent

Nonutility

Public

Cooperative

Federal

IOU

Nameplate Capacity

1992 1993 1994 1995 1996 1997 1998

0

20

40

60

80

-20

Percent

Nonutility

Federal

IOU

Public Cooperative

 Number of Companiesa

1992 1993 1994 1995 1996 1997 1998

0

5

10

15

20

-5

-10

Percent

Nonutility

Federal

Cooperative

Public

IOU

 Net Generation

1992 1993 1994 1995 1996 1997 1998

0

2

4

6

8

10

12

Percent

Nonutility

Cooperative

Public

Federal

IOU

 Additions to Capacity

Figure 16. Annual Growth Rate of Utility and Nonutility Nameplate Capacity, Net Generation, Additions to

Capacity, and Number of Companies, 1992-1998

lighting, railroads and railways, municipalities, divisions

or agencies of State and Federal Governments under

special contracts or agreements, and other utility departments.31

Sales to the residential sector in 1998 increased 20.1 percent from the 1992 level, to 1,128 billion kilowatthours,

which represented 35 percent of sales to ultimate

consumers. The 1998 commercial sector retail sales

increased 25 percent and the industrial sector 8 percent

from the 1992 levels. Together, these two non-residential

sectors accounted for 62 percent of 1998 retail sales.

Sales to the “other” sector were 104 billion kilowatthours

in 1998, an increase of 25 percent over 1992 levels

(Figures 19 and 20).

Retail Sales by Ownership Category

Sales by investor-owned electric utilities in 1998 increased 15.6 percent over 1992 levels and represented

 a Data for power marketers are not included.

 Sources: Energy Information Administration, Form EIA-759, “Monthly Power Plant Report,” Form EIA-860, “Annual Electric

Generator Report,” Form EIA-860A, “Annual Electric Generator Report % Utility,” Form EIA-861, “Annual Electric Utility Report,”

Form EIA 867, “Annual Nonutility Power Producer Report,” and Form EIA-860B, “Annual Electric Generator Report % Nonutility.”
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 27

Utility Purchasers

InvestorOwned

Utilities

Federal

Other

Publicly Owned

Cooperatives

From Utilities

(1,669 billion

kilowatthours)

808

12

247

2

7

3

426

424

From 

Nonutilities

(259 billion

kilowatthours)

Figure 17. Electric Utility Wholesale Power Purchases by Ownership Type, 1998

(Billion Kilowatthours)

 Source: 1985-1994: Energy Information Administration,

Annual Energy Review 1995, DOE/EIA-0384(95)

(Washington, DC, July 1996), Table 8.1. 1995-1998: Energy

Information Administration, Electric Power Annual 1998,

Volume II, DOE/EIA-0348(98)/2 (Washington, DC, December

1999), Tables 41-43.

Notes: Data do not include utility purchases from power marketers. Totals may not equal sum of components due to

independent rounding.

Source: Energy Information Administration, Form EIA-861, “Annual Electric Utility Report.”

1985 1987 1989 1991 1993 1995 1997

0

10

20

30

40

50

60

Billion Kilowatthours

Gross Imports

Net Imports

Gross Exports

Figure 18. U.S. International Electricity Trade,

1985-1998

939

774

967

83

1,128

969

1,040

104

Residential

Commercial

Industrial

Other

Sector

0 200 400 600 800 1,000 1,200 1,400

Total Retail Sales (Billion Kilowatthours)

1992

1998

Total 1992 Retail Sales: 2,763

Total 1998 Retail Sales: 3,240

969

967

Figure 19. Sales to Ultimate Consumers by Sector,

1992 and 1998

 Notes: Other includes sales for public street and highway

lighting, other sales to public authorities, sales to railroads and

railways, and interdepartmental sales. Totals may not equal

sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-861,

“Annual Electric Utility Report.”
28 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

32 Various additional industry summary statistics are provided in Appendix D.

Residential

Commercial

Industrial

Other

Sector

0 10 20 30 40 50 60 70 80 90 100

Percent

1992 1998

Figure 20. Share of Sales to Ultimate Consumers

by Sector, 1992 and 1998

2,100

387

221

55

2,428

486

280

47

Investor-Owned

Publicly Owned

Cooperative

Federal

Class

0 400 800 1,200 1,600 2,000 2,400 2,800

Total Sales (Billion Kilowattshours) 

1992 1998

Figure 21. Sales to Ultimate Consumers by Class

of Ownership, 1992 and 1998

Investor-Owned

Publicly Owned

Cooperative

Federal

Class

0 10 20 30 40 50 60 70 80 90 100

Percent

1992 1998

Figure 22. Share of Sales to Ultimate Consumers

by Class of Ownership,

1992 and 1998

 Notes: Other includes sales for public street and highway

lighting, other sales to public authorities, sales to railroads and

railways, and interdepartmental sales. Totals may not equal

sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-861,

“Annual Electric Utility Report.”

 Note: Totals may not equal sum of components because of

independent rounding.

 Source: Energy Information Administration, Form EIA-861,

“Annual Electric Utility Report.”

 Note: Totals may not equal sum of components because of

independent rounding.

 Source: Energy Information Administration, Form EIA-861,

“Annual Electric Utility Report.”

74.9 percent of sales to ultimate consumers. Publicly

owned utility sales increased 25.6 percent over 1992

levels and represented 15.0 percent of total sales.

Cooperative utility sales increased 26.7 percent over

1992 levels and represented 8.6 percent of sales. Federal

utility sales experienced a decrease of 14.5 percent from

1992 levels and represented 1.5 percent of the total retail

sales in 1998 (Figures 21 and 22).

Conclusion

This chapter has outlined the infrastructure of the electric power industry by defining its components and their

respective roles. In addition, it has provided statistics32

to clarify the roles and has compared current data to

historical data to show how the roles are changing due

to the opening of competition in the industry. In

addition, information was given regarding wholesale

and retail sales in an effort to more thoroughly cover the

roles of the components of the current electric power

industry. Some roles will continue to change throughout

the transition from a vertically integrated and regulated

monopoly to a functionally unbundled industry with a

competitive market for power generation. Market forces

will replace State and Federal regulators in setting the

price and terms of electricity supply and are expected to

lead to lower rates for customers. The individual States

are moving toward opening their retail markets to

competition. Chapter 8 details the role of the States in

promoting competition. The following chapter outlines

the Federal legislation that has affected the structure and

operating procedures of the electric power industry

since the 1930s.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 29

33 PUHCA and PURPA are now being targeted for repeal due to the industry’s transition to competition. Chapter 6 will address the

issues and arguments associated with the call for repeal, as well as current proposals for comprehensive restructuring legislation that are

before Congress. 34 L. S. Hyman, America's Electric Utilities: Past, Present and Future, Fifth Edition (Arlington, VA: Public Utilities Reports, Inc., 1994), p.

111.35 The Securities and Exchange Commission actually noted 142 registered holding companies in 1939. Securities and Exchange

Commission, Fifth Annual Report of the Securities and Exchange Commission, Fiscal Year Ended June 30, 1939 (Washington, DC, 1940), pp. 1 and

43. 36 T. J. Brennan et al., A Shock to the System: Restructuring America’s Electricity Industry (Resources for the Future: Washington, DC, July

1996), p. 160.

4. The Federal Statutory Background of the

Electric Power Industry

Introduction

This chapter describes major Federal legislation that has

shaped the electric power industry since the 1930s. It

begins by detailing three Acts that have had the most

profound effects on the industry's structure&the Public

Utility Holding Company Act of 1935 (PUHCA), the

Public Utility Regulatory Policies Act of 1978 (PURPA),33

and the Energy Policy Act of 1992 (EPACT), which led

to the issuance of Orders 888 and 889 by the Federal

Energy Regulatory Commission (FERC). The remainder

of the chapter lists and summarizes other laws which

have affected the industry throughout the years.

Appended to the end of the chapter is a list of major

Supreme Court cases which also have had an impact.

The Public Utility Holding

Company Act of 1935

The Public Utility Holding Company Act, enacted in

1935, was aimed at breaking up the unconstrained and

excessively large trusts that then controlled the Nation's

electric and gas distribution networks. They were

accused of many abuses, including “control of an entire

system by means of a small investment at the top of a

pyramid of companies, sale of services to subsidiaries at

excessive prices, buying and selling properties within

the system at unreasonable prices, intra-system loans at

unfair terms, and the wild bidding war to buy operating

companies.”34

Although more than 100 holding companies existed

before PUHCA, almost half of all electricity generated in

the United States was controlled by three huge holding

companies.35 The size and complexity of these huge

trusts made industry regulation and oversight control by

the States impossible. After the collapse of several large

holding companies, the Federal Trade Commission

(FTC) conducted an investigation after which it criticized the many abuses that tended to raise the cost of

electricity to consumers. The Securities and Exchange

Commission (SEC) also investigated and “publicly

charged that the holding companies had been guilty of

‘. . . stock watering and capital inflation, manipulation of

subsidies, and improper accounting practices.’ The

general counsel of the FTC went further, claiming that

‘[w]ords such as fraud, deceit, misrepresentation, dishonesty, breach of trust, and oppression are the only

suitable terms to apply.’” 36

Under PUHCA, the SEC was charged with the administration of the Act and the regulation of the holding

companies. One of the most important features of the

Act was that the SEC was given the power to break up

the massive interstate holding companies by requiring

them to divest their holdings until each became a single

consolidated system serving a circumscribed geographic

area. Another feature of the law permitted holding companies to engage only in business that was essential and

appropriate for the operation of a single integrated utility. This latter restriction practically eliminated the participation of nonutilities in wholesale electric power

sales. The law contained a provision that all holding

companies had to register with the SEC, which was

authorized to supervise and regulate the holding

company system. Through the registration process, the

SEC decided whether the holding company would need

to be regulated under or exempted from the require-
30 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

37 For a more extensive discussion of PUHCA, see Energy Information Administration, The Public Utility Holding Company Act of 1935:

1935-1992, DOE/EIA-0563 (Washington, DC, January 1993), pp. 39-53. 38 J. Seligman, The Transformation of Wall Street and The History of the Securities and Exchange Commission in Modern Corporate Finance,

(Boston, MA: Houghton, Mifflin Company, 1982), p. 134.

Table 6. Relative Size of Registered Holding Companies as of December 31, 1998

Holding Company System

Consolidated

Assets

(thousand

dollars)

Twelve Months’

Consolidated

Operating Revenues

(thousand dollars)

Number of

Customers

Retained

Earningsa

(thousand

dollars)

Allegheny Energy, Inc. (E) ......... 6,747,793 2,576,436 1,418,353 836,759

Alliant Energy Corp. (E) (G) ........ 4,959,000 2,131,000 1,295,500 537,372

Ameren (E) (G) ................. 8,847,439 3,318,208 1,479,365 1,472,200

American Electric Power Co. (E) .... 19,483,200 6,345,900 3,022,479 1,683,561

Central and South West Corp. (E) . . . 13,744,000 5,482,000 1,752,000 1,740,000

CINergy Corp. (E) (G) ............ 10,298,800 5,876,300 1,870,000 945,200

Columbia Energy Group (G) ....... 6,968,700 5,731,800 2,100,000 409,544

Conectiv (E) (G) ................ 6,100,000 3,100,000 1,049,706 276,939

Consolidated Natural Gas Co. (G) . . . 6,361,900 2,760,400 1,880,000 1,591,543

Eastern Utilities Associates (E) ..... 1,302,638 538,801 305,018 56,062

Entergy Corp. (E) ................ 22,848,023 11,494,772 2,495,000 2,526,888

GPU Corp. (E) .................. 16,288,109 4,248,792 2,041,000 2,230,425

National Fuel Gas Co. (G) ......... 2,684,459 1,248,000 704,217 428,112

New Century Energies (E) (G) ...... 7,672,000 3,610,900 2,658,000 740,677

New England Electric System (E) .... 5,070,535 2,420,533 1,363,000 998,912

Northeast Utilities (E) ............. 10,387,381 3,767,714 1,729,250 560,769

PECO Energy Power Co. (E) ....... 118,000 18,500 NA NA

Southern Co. (E) ................ 36,192,000 11,403,000 3,794,000 3,878,000

Unitil Corp. (E) (G) ............... 376,855 149,639 114,500 36,401

 Total ........................ 186,450,832 76,222,695 31,071,388 20,949,364

a

Retained earnings are the balance, either debit or credit, of appropriated or unappropriated earnings of an entity that are retained

in the business.

E = Electric.

G = Gas.

NA = Not applicable.

Source: Securities and Exchange Commission, Financial and Corporate Report (Washington, DC, July 1, 1999), p. 3.

ments of the Act. The SEC also was charged with

regulating the issuance and acquisition of securities by

holding companies. Strict limitations on intrasystem

transactions and political activities were also imposed.37

The holding companies at first resisted compliance, and

some challenged the constitutionality of the Act, but the

Supreme Court upheld PUHCA's legality. By 1947,

virtually all holding companies had undergone some

type of simplification or integration, and by 1950 the

utility reorganizations were virtually complete.38 As of

December 31, 1998, there were only 15 registered

holding companies in the Unites States (Table 6).

Additionally, there were 53 holding companies exempt

from SEC regulation by SEC order, and 112 holding

companies exempt since they fell under the umbrella of

PUHCA Section 3 (a) (1) and/or (2), which states:

The Commission . . . shall exempt any holding company,

and every subsidiary company thereof . . . from any . . .

provisions of this title . . . unless it finds the exemption

detrimental to the public interest or the interest of

investors or consumers if&(1) such holding company,

and every subsidiary company thereof . . . are predominantly intrastate in character and carry on their

business substantially in a single State in which such

holding company and every such subsidiary company

thereof are organized;
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 31

39 Public Utility Holding Company Act of 1935 (Public Law 74-333), Section 3. 40 J. H. Minan and W. H. Lawrence, “Federal Tax Incentives and Solar Energy Development,” Energy Law Service, Monograph 7F

(Wilmette, IL, September 1981), p. 5. 41 Public Utility Regulatory Policies Act of 1978 (Public Law 95-617), Section 2. 42 The law required electric utilities to purchase electricity from qualified facilities at “a rate which [does not] exceed the incremental

cost to the electric utility of alternative electric energy . . . [which the] utility would generate or purchase from another source.” Public Utility

Regulatory Policies Act of 1978 (Public Law 95-617), Title II, Section 210, Paragraphs (b), (2), and (d).

(2) such holding company is predominantly a public utility

company whose operations . . . do not extend beyond the

State in which it is organized and States contiguous

thereto.39

Although PUHCA reform or outright repeal is being

considered today because of the move to restructure (see

Chapter 6), the same plea for change has been made

several times over the past 20 years. In the 1970s,

utilities sought relief from PUHCA constraints to

diversify into nonutility lines of business as a means to

improve their declining profits. In the 1980s, they sought

to diversify to exploit the positive experience of independent power producers under PURPA, which

eliminated PUHCA constraints on certain qualifying

generating facilities. It was not until 1992 that EPACT

significantly modified PUHCA by allowing both utilities

and nonutilities to build, own, and operate power plants

for wholesaling electricity in more than one geographic

area. A more detailed discussion of the effects of PURPA

and EPACT on PUHCA provisions follows.

The Public Utility Regulatory

Policies Act of 1978

In October 1973, Nations of the Organization of Petroleum Exporting Countries (OPEC) imposed a ban on oil

exports to the United States. Although the ban lasted

only until March 1974, its effects increased public

awareness of energy issues, resulted in higher energy

prices, contributed to inflation, and acted as a catalyst

for the proposal and adoption of the National Energy

Act. This Act, which was signed into law in November

1978, comprises five different statutes: PURPA, the

Energy Tax Act, the National Energy Conservation

Policy Act, the Powerplant and Industrial Fuel Use Act,

and the Natural Gas Policy Act. The general purpose of

the National Energy Act was to ensure sustained

economic growth while also permitting the economy

time to make an orderly transition from the past era of

inexpensive energy resources to a period of more costly

energy.40 Although it had numerous objectives, a

primary goal of the National Energy Act was to reduce

the Nation's dependence on foreign oil and its vulnerability to interruptions in energy supply. Another

was to develop renewable and alternative energy

sources.

The most significant part of the National Energy Act of

1978 with regard to the structure of the electric power

industry was PURPA, specifically, Section 2 of the Act:

The Congress finds that the protection of the public

health, safety, and welfare, the preservation of national

security, and the proper exercise of congressional

authority under the Constitution to regulate interstate

commerce require&

(1) a program providing for increased conservation of

electric energy, increased efficiency in the use of

facilities and resources by electric utilities, and

equitable retail rates for electric consumers,

(2) a program to improve the wholesale distribution of

electric energy, the reliability of electric service, the

procedures concerning consideration of wholesale rate

applications before the Federal Energy Regulatory

Commission, and to provide other measures with

respect to the regulation of the wholesale sale of electric

energy,

(3) a program to provide for the expeditious development of hydroelectric power . . .41

Section 210 of PURPA requires electric utilities to interconnect with and buy whatever amount of capacity and

energy is offered from any facility meeting the criteria

for a qualifying facility (QF) (see inset). It further

requires that the utility pay for that power at the utility's

own incremental or avoided cost of production.42 This

provision created a market in which QFs could

unilaterally sell electricity to utilities. To further ease the

burden on nonutility companies wishing to enter the

electric generating market, Congress exempted most

QFs from rate and accounting regulation by FERC under

the Federal Power Act, from regulation by the SEC

under PUHCA, and from State rate, financial, and

organizational regulation of utilities. It also simplified

contracts, streamlined the power sales process, increased

financial certainty for creditors and equity sponsors, and

generally eliminated several procedural and planning
32 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

43 Energy Information Administration, Renewable Energy Annual 1995, DOE/EIA-0603(95) (Washington, DC, December 1995), p. xxvi.

problems that had made entry into the electricity market

prohibitive for most of the smaller energy producers.43

In enacting PURPA, Congress ensured that QFs had a

guaranteed market for their power at a price equal to the

avoided cost of the utilities that purchased their power.

This is quite different from traditional regulation, which

generally sets the price of electricity on the basis of the

cost (to the producer) of producing it. The QFs themselves are not subject to cost-of-service regulation, and

the prices paid to them are not based on their cost of

producing the electricity. Instead, the prices they are

paid reflect the avoided cost of the purchasing utility,

that is, the cost the utility avoided by not producing the

electricity received from the QF or purchasing it from

another source. One initial interpretation of avoided cost

under PURPA was the cost of additional electricity

produced by the utility itself. However, under PURPA's

requirements, some utilities had to purchase QF generation even though they already had sufficient supply

available to meet demand, either through their own

generation or through purchases from other sources.

PURPA Qualification Criteria

PURPA was designed to encourage the efficient use of fossil fuels in electric power production through cogenerators and the

use of renewable resources through small power producers. There is no size limitation for an eligible solar, wind, or waste

facility, as defined by section 3(17) (E) of the Federal Power Act. For a non-eligible facility, the power production capacity for

which qualification is sought may not exceed 80 megawatts. (Under PURPA provisions, both cogenerators and small power

producers cannot have more than 50 percent of their equity interest held by an electric utility.)a

Cogenerators

Cogenerators are generators that sequentially or simultaneously produce electric energy and another form of energy

(such as heat or steam) using the same fuel source. Cogeneration technologies are classified as “topping-cycle” and

“bottoming-cycle” systems. In a typical topping-cycle system,

high-temperature, high-pressure steam from a boiler is used to

drive a turbine to generate electricity. The waste heat or steam

exhausted from the turbine is then used as a source of heat for

an industrial or commercial process. In a typical bottomingcycle system, high-temperature thermal energy is produced

first for applications such as reheat furnaces, glass kilns, or

aluminum metal furnaces, and heat is then extracted from the

hot exhaust stream of the primary application and used to

drive a turbine. Bottoming-cycle systems are generally used in

industrial processes that require very high-temperature heat.

For a nonutility to be classified as a cogenerator qualified

under PURPA, it must meet certain ownership, operating, and

efficiency criteria established by FERC. The operating

requirements stipulate the proportion (applicable to oil-fired

facilities) of output energy that must be thermal energy, and

the efficiency requirements stipulate the maximum ratio of

input energy to output energy. 

Renewables

A renewable resource is an energy source that is regenerative

or virtually inexhaustible. Renewable energy includes solar,

wind, biomass, waste, geothermal, and water (hydroelectric).

Solar thermal technology converts solar energy through high

concentration and heat absorption into electricity or process

energy. Wind generators produce mechanical energy directly

through shaft power. Biomass energy is derived from

hundreds of plant species, various agricultural and industrial

residues, and processing wastes. Industrial wood and wood

waste are the most prevalent form of biomass energy used by

nonutilities. Geothermal technologies convert heat naturally

present in the earth into heat energy and electricity.

Hydroelectric power is derived by converting the potential

energy of water to electrical energy using a hydraulic turbine

connected to a generator.

For a nonutility to be classified as a small power producer

under PURPA, it also must meet certain ownership and

operating criteria established by FERC. In addition, renewable

resources must provide at least 75 percent of the total energy

input. PURPA provisions enabled nonutility renewable

electricity production to grow significantly, and the industry

responded by improving technologies, decreasing costs, and

increasing efficiency and reliability.

a

 For further information regarding criteria, refer to http://frwebgate.access.gpo.gov.

In the mid-1980s, several States began to review their

own and others' experiences with PURPA implementation. Maine, in particular, concluded that avoided

costs could be established through competitive bidding

among QFs, as opposed to setting them administratively. In 1984, Central Maine Power (CMP) and the

Maine Public Service Commission (PSC) became the first

to put competitive bidding into practice. CMP did this

in an effort to protect itself from oversupply of electricity by QFs after the PSC had previously decided that

avoided-cost rates for QFs were to be based on the cost

of production of electricity by nuclear facilities. These

high rates spurred a larger volume of offers than CMP

needed. The switch to market-based pricing provided
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 33

44 W. H. Wellford and H. E. Robertson, “Bidding for Power: The Emergence of Competitive Bidding in Electric Generation,” Working

Paper No. 2, National Independent Energy Producers (March 1990), p. 3. 45 An EWG is a corporate entity. An EWG-owned facility is called an “eligible facility.” In this report, “EWG” refers to an EWG-owned

eligible facility. 46 Southeastern Power Administration v. Kentucky Utilities Company, 25 FERC § 61,204 (1983).

a new avoided cost for purchased power from QFs that

was below the initial avoided cost levels that would

have prevailed in the absence of bidding.44

The Energy Policy Act of 1992

In 1992, President George Bush signed the Energy Policy

Act (EPACT). The Act substantially reformed PUHCA

and made it even easier for nonutility generators to enter

the wholesale market for electricity by exempting them

from PUHCA constraints. The law created a new

category of power producers, called exempt wholesale

generators (EWGs).45 By exempting them from PUHCA

regulation, the law eliminated a major barrier for utilityaffiliated and nonaffiliated power producers who want

to compete to build new non-rate-based power plants.

EWGs differ from PURPA QFs in two ways. First, they

are not required to meet PURPA's cogeneration or

renewable fuels limitations. Second, utilities are not

required to purchase power from EWGs. Marketing of

EWG power has come to be facilitated by transmission

provisions that gave FERC the authority to order utilities

to provide access to their transmission systems.

The law has been hailed by industry analysts as one of

the most significant pieces of legislation in the history of

the industry. In addition, the law amended the wholesale transmission provisions of the Federal Power Act.

These transmission provisions have led to a nationwide

open-access electric power transmission grid for wholesale transactions. (The law specifically prohibits FERC

from ordering retail wheeling&the transmission of

power to a final customer.) Independent power producers, publicly owned utilities, rural cooperatives, and

industrial producers (i.e., anyone selling power at

wholesale) gained the ability to seek from FERC orders

that require transmission-owning utilities to provide

transmission service at FERC-defined “just and reasonable” rates.

The language of the law concerning pricing directs

FERC, when it issues a transmission order, to approve

rates which permit the utility to recover “all legitimate,

verifiable economic costs incurred in connection with the

transmission services.” Such costs include “an appropriate share, if any, [of] necessary associated services,

including, but not limited to, an appropriate share of any

enlargement of transmission facilities.” The language

also says that FERC “shall ensure, to the extent

practicable,” that costs incurred by the wheeling utility

are recovered from the transmission customer rather

than “from a transmitting utility's existing wholesale,

retail, and transmission customers.”

Probably the most salient characteristics of EPACT were

the expansion of FERC’s authority and the creation of

EWGs that were exempt from SEC regulation. A bitter

dispute was in the area of transmission access. Some

nonutility groups had argued that not revising transmission-access rules would reinforce the utility

monopolistic structure. The main thrust of the argument

against these transmission access authority revisions

was that the high level of reliability enjoyed by the

Nation would be compromised.

Although regulated public utilities had no general

obligation to provide access to their transmission lines

before EPACT, there are several restricted exceptions to

this generalization. One is the requirement, under

PURPA, that utilities interconnect with and purchase

power from QFs. Another is that under the Federal

Power Act, as amended by PURPA, FERC had the

authority to require wheeling under limited circumstances. But, in its first deliberation on this authority,

FERC found that the authority was limited so that it did

not allow FERC to require a utility to wheel power to its

wholesale customers or to encourage competition in

bulk power markets.46 This interpretation of PURPA

circumscribed the conditions under which FERC could

order wheeling but FERC’s interpretation was later

upheld by the courts. The enactment of EPACT in 1992

broadened FERC’s authority to order utilities to provide

wheeling over their transmission systems to utilities and

nonutilities. In addition, anti-trust laws and analyses

have been used to require access to transmission and

generation capacity. FERC’s implementation of EPACT

and open transmission access is discussed in Chapter 7.

The following table lists Federal legislation which has

impacted the electric power industry since 1933.
34 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Major Federal Legislation Affecting the Electric Power Industry

Tennessee Valley Authority Act of 1933

(Public Law 73-17)

Under this law, the Federal Government provided electric power to States, counties, municipalities, and nonprofit cooperatives.

It was the steady continuation of Federal initiatives to provide navigation, flood control, strategic materials for national defense,

electric power, relief of unemployment, and improvement of living conditions in rural areas. The Tennessee Valley Authority (TVA)

was also authorized to generate, transmit, and sell electric power. With regard to the sale of electric power, the TVA is authorized

to enter into contracts up to 20 years for sales to governmental and private entities, to construct transmission lines to areas not

otherwise supplied with electricity, to establish rules and regulations for power sales and distribution, and to acquire existing

electric facilities used in serving certain areas.

Public Utility Holding Company Act of 1935 (PUHCA)

(Public Law 74-333)

PUHCA was enacted to remedy utility industry abuses facilitated by the holding company structure. PUHCA gave the Securities

and Exchange Commission the authority to oversee utility holding companies pursuant to the extensive set of regulations

provided by the Act.

Federal Power Act of 1935 (Title II of PUHCA)

(Aug. 26, 1935, ch. 687, Title II, 49 Stat. 838)

This Act was passed to provide for a Federal mechanism for interstate electricity regulation. 

Rural Electrification Act of 1936

(Public Law 74-605)

This Act established the Rural Electrification Administration (REA) to provide loans and assistance to organizations providing

electricity to rural areas and towns with populations under 2,500. REA cooperatives are generally associations or corporations

formed under State law. The predecessor to this Act was the Emergency Relief Appropriations Act of 1935, which performed

the same function.

Bonneville Project Act of 1937

(Public Law 75-329)

This Act created the Bonneville Power Administration (BPA), which pioneered the Federal power marketing administrations. The

BPA was accountable for the transmission and marketing of power produced at Federal dams in the Northwest. In 1953, the BPA

first guaranteed the bonds of and a market for small energy facilities built and financed by public utility districts.

Reclamation Project Act of 1939

(Public Law 76-260)

This Act requires that rates for electric power generated at Federal hydroelectric projects be sufficient to recover an appropriate

share of annual operation and maintenance costs and an appropriate share of construction costs, to include interest charged

at a rate of not less than 3 percent.

Flood Control Act of 1944

(Public Law 78-534)

This Act formed the basis for the later creation of the Southeastern Power Administration (SEPA)a

 in 1950 to sell power produced

by the U.S. Army Corps of Engineers in the Southeast; and the Alaska Power Administration (APA)b

 in 1967 to both operate and

market power from two hydroelectric plants in Alaska: the Eklutna Project and the Snettisham Project. Although the Southwestern

Power Administration’s (SWPA)c

 authority after World War II came from the Flood Control Act of 1944, it was established using

the Executive Branch’s emergency war powers authority to satisfy the growing demands from weapons development and

domestic needs. This Act also demands that rates for electric power be enough to recover the cost of “producing and transmitting

such electric energy.”

d
Major Federal Legislation Affecting the Electric Power Industry (Continued)

Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 35

First Deficiency Appropriation Act of 1949

(Public Law 81-71)

The Act authorized the Tennessee Valley Authority to construct thermal-electric power plants for commercial electricity sale.

Energy Supply and Environmental Coordination Act of 1974 (ESECA)

(Public Law 93-319)

This Act allowed the Federal Government to prohibit electric utilities from burning natural gas or petroleum products.

DOE Organization Act of 1977

(Public Law 95-91)

In addition to forming the Department of Energy (including the Federal Energy Regulatory Commission), this Act provided

authority for the establishment of the Western Area Power Administration (WAPA)e and transferred power marketing

responsibilities and transmission assets previously managed by the Bureau of Reclamation to WAPA. WAPA’s authority was

extended through the Hoover Power Plant Act of 1984. This Act also transferred the other four power marketing administrations

(PMAs)&the Southeastern Power Administration, the Southwestern Power Administration, the Alaska Power Administration, and

the Bonneville Power Administration&from the Department of the Interior to the Department of Energy.

National Energy Act of 1978

(Public Law 95-617 - 95-621)

This Act was signed into law in November 1978 and includes five different statutes: the Public Utility Regulatory Policies Act

(PURPA), the Energy Tax Act (Public Law 95-618), the National Energy Conservation Policy Act (Public Law 95-619), the

Powerplant and Industrial Fuel Use Act (Public Law 95-620), and the Natural Gas Policy Act (Public Law 95-621). Passed in the

wake of the oil-producing nations’ ban on oil exports to the United States and retail oil price increases, its general purpose was

to ensure sustained economic growth while also permitting the economy time to make an orderly transition from the past era

of inexpensive energy resources to a period of more costly energy.

Public Utility Regulatory Policies Act of 1978 (PURPA)

(Public Law 95-617)

PURPA was passed in response to the unstable energy climate of the late 1970s. PURPA sought to promote conservation of

electric energy. Additionally, PURPA created a new class of nonutility generators, small power producers, from which, along with

qualified cogenerators, utilities are required to buy power. Further, PURPA gave FERC the authority to order wheeling under

the FPA.

Energy Tax Act of 1978 (ETA)

(Public Law 95-618)

This Act, like PURPA, was passed in response to the unstable energy climate of the 1970s. The ETA encouraged conversion

of boilers to coal and investment in cogeneration equipment and solar and wind technologies by allowing a tax credit on top of

the investment tax credit. It was later expanded to include other renewable technologies. However, the incentives generally were

curtailed as a result of tax reform legislation in the mid-1980s.

National Energy Conservation Policy Act of 1978 

(Public Law 95-619)

This Act required utilities to develop residential energy conservation plans to encourage slower growth of electricity demand.

Powerplant and Industrial Fuel Use Act of 1978 

(Public Law 95-620)

This Act succeeded the Energy Supply and Environmental Coordination Act of 1974, and extended Federal prohibition on the

use of natural gas and petroleum in new electric power plants.
Major Federal Legislation Affecting the Electric Power Industry (Continued)

36 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Pacific Northwest Electric Power Planning and Conservation Act of 1980

(Public Law 96-501)

This Act created the Pacific Northwest Electric Power and Conservation Council to coordinate the conservation and resource

acquisition planning of the Bonneville Power Administration (BPA). The Act also provides for BPA to purchase and exchange

electric power with Northwest utilities at the “average system cost.” Approval of the methodology for determining “average

system cost” is required. This Act also gave the BPA the authority to plan for and acquire additional power to meet its growing

load requirements.

Economic Recovery Tax Act of 1981

(Public Law 97-34)

This Act introduced a new methodology for determining allowable tax depreciation deductions. The new methodology, the

Accelerated Cost Recovery System (ACRS), set forth rules enabling taxpayers to claim generous depreciation deductions based

on the system’s permitted depreciable life, method, and salvage value assumptions. The generation, transmission, and

distribution plants of regulated electric utilities were categorized as public utility property. Public utility property under ACRS was

assigned relatively long depreciable lives.

Electric Consumers Protection Act of 1986 (ECPA) 

(Public Law 99-495)

This Act was the first significant amendment to the hydro licensing provisions of the FPA since 1935. “The amendments have

made four principal changes to Part I of the FPA. First, the municipal preference on relicensing has been eliminated. Second,

the importance of environmental considerations in the licensing process has been greatly increased and the role of the State

and Federal fish and wildlife agencies is expanded. Third, PURPA benefits for hydroelectric projects at new dams and diversions

were eliminated unless the projects satisfy stringent environmental conditions. Finally, FERC’s enforcement powers have been

increased substantially.”

f

Tax Reform Act of 1986

(Public Law 99-514)

Under this Act, ACRS was replaced with the Modified Accelerated Cost Recovery System (MACRS). Under MACRS, the disparity

in treatment of property between regulated and nonregulated taxpayers was eliminated. The investment credit was also repealed.

The investment credit of the Federal income tax law was a dollar-to-dollar offset against the taxes payable by the taxpayer. The

investment credit was available for regulated and nonregulated taxpayers and was intended to encourage capital investment

by the Nation’s businesses. The credit continues to be of importance to regulated utilities, however, because it is generally

amortized for ratemaking and financial reporting purposes over the regulatory life of the related property that gave rise to the

credit.

Clean Air Act Amendments of 1990 (CAAA)

(Public Law 101-549)

These Amendments established a new emissions-reduction program. The goal of the legislation was to reduce annual sulfur

dioxide emissions by 10 million tons and annual nitrogen oxide emissions by 2 million tons from 1980 levels for all man-made

sources. Generators of electricity will be responsible for large portions of the sulfur dioxide and nitrogen oxide reductions. The

program instituted under the Clean Air Act Amendments of 1990 employs a unique, market-based approach to sulfur dioxide

emission reductions, while relying on more traditional methods for nitrogen oxide reductions.

Energy Policy Act of 1992 (EPACT)

(Public Law 102-486)

This Act created a new category of electricity producer, the exempt wholesale generator, which narrowed PUHCA's restrictions

on the development of nonutility electricity generation. The law also authorized FERC to open up the national electricity

transmission system to wholesale suppliers.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 37

a

SEPA markets power in West Virginia, Virginia, North Carolina, South Carolina, Georgia, Florida, Alabama, Mississippi,

Tennessee, and Kentucky. SEPA is unique from the other marketing authorities because it does not own any transmission lines. b

The APA and the TVA are the only two Federal marketing organizations that operate their own plants.

c

SWPA markets power in Arkansas, Kansas, Louisiana, Missouri, Oklahoma, and Texas.

d

Energy Information Administration, Financial Statistics of Major U.S. Publicly Owned Electric Utilities 1994, DOE/EIA0437(94)/2 (Washington, DC, December 1995), p. 458. e

The territory served by WAPA includes 15 Central and Western States of Arizona, California, Colorado, Iowa, Kansas,

Minnesota, Montana, Nebraska, Nevada, New Mexico, North Dakota, South Dakota, Texas, Utah, and Wyoming. The WAPA’s

authority was lengthened through the Hoover Power Plant Act of 1984 to constrain customer utilities to address certain

conservation activities and to retain a part of customers’ power allocations if they did not follow. f

D. J. Muchow and W. A. Mogel, Energy Law and Transactions (Matthew Bender, April 1996), p. 53-20.

Note: Although it is not a law, the Uniform Division of Income for Tax Purposes Act (UDITPA)&which provides that the sale

of electricity is sourced for apportionment purposes to the ultimate destination State&has been adopted in some form by 44

States from a total of 47 States that impose a corporate income tax. Public laws before 1935 were sourced differently than those

after 1935. For more information on the power marketing administrations, refer to Energy Information Administration, Financial

Statistics of Major U.S. Publicly Owned Electric Utilities 1994, DOE/EIA-0437(94)/2 (Washington, DC, December 1995).

Source: This inset is based on information compiled by the Office of Coal, Nuclear, Electric and Alternate Fuels from various

documents. These documents include Congressional Quarterly as well as others published by the following organizations: the

Congressional Research Service, Government Institutes, Inc., the Council on Environmental Quality, the General Accounting

Office, and the Federal Energy Regulatory Commission. Also refer to D. J. Muchow and W. A. Mogel, Energy Law and

Transactions (Matthew Bender, April 1996).

In addition to the preceding statutory background regarding the electric power industry, the inset below

provides a synopsis of a related subject&U.S. Supreme

Court cases and decisions that have had major impacts

on the industry.

Major U.S. Supreme Court Cases Affecting the Electric Power Industrya

Court Case Date Decision

Munn v. Illinois

(94 U.S. 113)

1877 The Supreme Court establishes the rights of government to regulate and set

rates for companies that provide vital public services in a business

environment.

Smyth v. Ames

( 169 U.S. 466)

1898 The Supreme Court decrees just compensation on fair value. The decision

in this case upheld the right of the State to regulate the prices charged to

the public by a business “affected with a public interest.”

Rhode Island PUC v. Attleboro

(273 U.S. 83)

1927 The Supreme Court declares that selling electricity interstate cannot be

regulated by a State.

Ashwander v. TVA

(297 U.S. 288) 

1936 The Supreme Court upholds the constitutionality of the Tennessee Valley

Authority.

Electric Bond & Share v. SEC

(303 U.S. 419)

1938 The Supreme Court upholds the Public Utility Holding Company Act of 1935.

Tennessee Electric Power Co. v.

Tennessee Valley Authority

(306 U.S. 118)

1939 The Supreme Court rules in TVA’s favor, despite the claims that TVA

threatened the large investments already made by privately owned utilities.

This ruling resulted in TVA becoming a major electricity supplier in the

region.

F.P.C. v. Hope Natural Gas

(320 U.S. 591)

1944 The Supreme Court closes a longstanding dispute by allowing either original

or replacement cost accounting in utility rate making, so long as just and

reasonable rates result.

Otter Tail Power Co. v. United

States

(410 U.S. 366)

1973 The Supreme Court upholds finding that Otter Tail Power Co. violated

Section 2 of the Sherman Act by refusing to sell or wheel wholesale power

to proposed municipal systems.
Major U.S. Supreme Court Cases Affecting the Electric Power Industry (Continued)

Court Case Date Decision

38 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

FPC v. Conway Corp.

(426 U.S. 271)

1976 The Supreme Court states that FERC, in setting wholesale rates, must

consider allegations that the proposed rates are discriminatory and

anticompetitive in effect.

FERC v. Mississippi

(456 U.S. 742)

1982 The Supreme Court upholds the constitutionality of PURPA in regards to its

preemptive effect on the States’ authority.

American Paper Institute v.

American Electric Power Service

Corp.

(461 U.S. 402)

1983 The Supreme Court upholds the constitutionality of FERC’s cogeneration

rules promoted pursuant to PURPA. 

Nantahala Power & Light Co. v.

Thornburg

(476 U.S. 953)

1986 Among other outcomes, the Supreme Court confirms that FERC has

exclusive authority over wholesale electric rates.

Mississippi Power & Light Co. v.

Mississippib

(487 U.S. 354)

1988 The Supreme Court determines that FERC authority is controlling and that a

State commission is obligated to honor a FERC order. The Court stated

“FERC-mandated allocations of power are binding on States, and States

must treat those allocations as fair and reasonable when determining retail

rates.”

c

Duquesne Light Co. v. Baraschd

(488 U.S. 299)

1989 “U.S. Supreme Court held that absent any showing that a State’s ratemaking methodology results in unreasonable rates that throw into jeopardy

the financial integrity of the utilities or otherwise fail to compensate

shareholders for their risks of investment, no impermissible taking exists.

Further, the Constitution of the United States does not mandate any

particular rate-making methodology for State regulatory commissions.”

e

a

This inset highlights the major U.S. Supreme Court cases that affect the electric power industry, stating the final decision of

the Court without discussing in detail the contents of the case.

b

This case, Mississippi Power & Light Co. v. Mississippi, continues the holding found by the U.S. Supreme Court in the

Nantahala Power & Light Co. v. Thornburg case.

c

W. F. Fox, Jr., Regulatory Manual Series: Federal Regulation of Energy (Shepard’s/McGraw-Hill, Inc., 1993), p. 149. d

This case is a final construction work in progress (CWIP) case. FERC issued a CWIP rule effective July 1, 1983. This means

that a utility may include, in its rate base, up to 50 percent of its CWIP costs for ongoing construction projects and for the costs

of nuclear fuel in the process of fuel refinement, conversion, enrichment, and fabrication. In addition, the rule continues to permit

utilities to include all CWIP costs associated with pollution control and fuel conversion facilities. See W. F. Fox, Jr., Regulatory

Manual Series: Federal Regulation of Energy (Shepard’s/McGraw-Hill, Inc., 1993), p. 150. e

W. F. Fox, Jr., Regulatory Manual Series: Federal Regulation of Energy (Shepard’s/McGraw-Hill, Inc., 1993), p. 153.

FERC = Federal Energy Regulatory Commission.

TVA = Tennessee Valley Authority.

PG&E = Pacific Gas & Electric Company.

PURPA = Public Utility Regulatory Policies Act.

PUC = Public Utility Commission.

Source: This inset is based on information compiled by the Office of Coal, Nuclear, Electric and Alternate Fuels from various

documents from the Department of Energy Library. For more information, refer to D. J. Muchow and W. A. Mogel, Energy Law

and Transactions (Matthew Bender, April 1996); and W. F. Fox, Jr., Regulatory Manual Series: Federal Regulation of Energy

(Shepard’s/McGraw-Hill, Inc., 1993).
Part II:

The U.S. Electric Power Industry

in Transition to Competition
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 41

47 P. Huber, “Is a Breakup Next? Not Likely,” The Wall Street Journal (April 4, 2000), p. A26. 48 California, Idaho, Illinois, Missouri, Montana, New Hampshire, New York, Oregon, Pennsylvania, Rhode Island, and Washington.

5. Factors Underlying the Restructuring

of the Electric Power Industry

Introduction

In recent years, economists and public policy analysts

have extolled the advantages of competition over regulation and have promoted the idea that free markets can

drive down costs and prices by reducing inefficiencies.

Competitive industries may also be more likely to spur

innovations with new technologies. Recent actions with

regard to electric power by legislators and regulators in

the United States are evidence of the changing approach

to dealing with what until recently has been a regulated

monopoly. Originally, protecting consumers was a primary motivation for decisions to impose regulatory

constraints on the industry. Today, legislators and

regulators are making laws and rules that promote

competition across the economy for the same purpose,

because they believe that consumers will benefit more

from an industry whose members must compete for

customers than from an industry composed of regulated

monopolies. 

One example is the 1999 revocation of the Bank Act of

1933. Like the Public Utility Holding Company Act of

1935 mentioned in Chapter 2 and later outlined in

Chapter 4, it was another piece of Depression-era

legislation that was believed to have become obsolete.

That law had been passed to separate commercial

banking from investment banking (the underwriting of

securities). Subsequent pressure from both commercial

and investment bankers and from the insurance industry, promoting synergies that the Act was ostensibly

constraining, led to its repeal. 

The most important and controversial sections of the

Telecommunications Act of 1996, and the Federal

Communications Commission’s regulations implementing it, concern the unbundling of the local phone

company’s network elements down to the level of

virtual space (bandwidth) within the individual

telephone line leading to a residence. The same thinking

is now being applied to the electric power industry in

that it is now a target for unbundling along similar lines,

with power generation and sales being untangled from

transmission and distribution services.47 Other examples

of this changed climate can be found throughout the

State and Federal levels as well as other countries

around the world. In the United States, the Energy

Policy Act of 1992 (EPACT) was passed by Congress to

promote competition in electricity generation. The recent

spate of generating asset sales (some utilities with

enormous holdings of generating capacity have sold or

are planning to sell their entire inventories) is at least

partly a result of EPACT. In 1998, retail sales in

deregulated markets occurred in 11 States.48 With the exception of Missouri, all of these States had deregulated

market sales in the industrial sector and all but Idaho,

Montana, and Rhode Island had sales to commercial

customers in deregulated markets. Those that did not

have residential sales in deregulated markets were

Idaho, Missouri, Montana, and Washington. As of

July 1, 2000, 24 States and the District of Columbia had

passed legislation or issued regulatory orders to restructure the electric power industries within their borders.

Only eight States have taken little or no action toward

restructuring (Figure 23). This changed climate and the

legislative and regulatory actions that have resulted are

one of the three factors underlying restructuring that are

outlined in this chapter. 

For most of the industry’s history, consumers welcomed

the protection that regulation afforded them and felt that

this means of oversight assured them of fair prices for

electricity. Now, however, consumers themselves are

pushing for competition (to both lower prices and

increase the variety of suppliers such as green power

producers) and regulatory reform. The main thrust is

coming from large industrial users of electricity who, in

some areas of the United States, have been burdened by

high electricity prices while their competitors in other

areas pay far less for their electricity. These price differentials are the second factor underlying the restructuring

of the industry. 
42 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

49 An exception is Florida, where it was ruled that merchant plants planning to sell their power outside State boundaries cannot be built

in the State. 50 Variable operations and maintenance costs at nuclear plants are less than those at combined-cycle plants. 51 Energy Information Administration, Assumptions to the Annual Energy Outlook, DOE/EIA-0554 (Washington DC, January 2000),

Table 37, Cost and Performance Characteristics of New Central Station Electricity Generating Technologies. 52 The Clean Air Act Amendments of 1990 established the Environmental Protection Agency’s Acid Rain Program where allowances

permitting the emission of sulfur dioxide may be bought and sold on the open market. Similarly, the Amendments led to the establishment

of the Ozone Transport Commission which formed a market, albeit regionally limited, for nitrogen oxide allowances. 53 T.R. Kuhn, et al., “Electric Utility Deregulation Sparks Controversy,” Harvard Business Review (May/June 1996), p. 150.

Restructuring Legislation Enacted

Comprehensive Regulatory Order Issued

Commission or Legislative Investigation Ongoing

Legislation/Orders Pending

No Activity

1

2

3

4

5

Figure 23. Status of State Electric Utility

Deregulation Activity, as of July

2000

1

Arizona, Arkansas, California, Connecticut, Delaware, District of

Columbia, Illinois, Maine, Maryland, Massachusetts, Michigan,

Montana, Nevada, New Hampshire, New Jersey, New Mexico,

Ohio, Oklahoma, Oregon, Pennsylvania, Rhode Island, Texas,

Virginia, and West Virginia.

2

New York.

3

Alaska and South Carolina.

4

Alabama, Colorado, Florida, Indiana, Iowa, Louisiana,

Minnesota, Mississippi, Missouri, North Carolina, North Dakota,

Utah, Vermont, Washington, Wisconsin, and Wyoming.

5

Georgia, Hawaii, Idaho, Kansas, Kentucky, Nebraska, South

Dakota, and Tennessee 

Source: Energy Information Administration,

 http://www.eia.doe.gov/cneaf/electricity/chg_str/regmap.html.

A third factor that has had a significant impact on

restructuring is the technological innovation in the

production of electricity. Nonutilities, using recently

improved aero-derivative gas turbine technologies to

generate electricity, can now do so cheaply enough that

merchant plants are being built in many areas of the

country where they are permitted.49 Today, with one

exception,50 the capital costs and both the fixed and

variable operations and maintenance costs of combinedcycle plants, and conventional and advanced combustion turbines, are lower than the traditional baseload

coal and nuclear technologies.51 Also, the advanced

generators are cleaner than coal plants and some are

more efficient. Today’s regulatory environment includes

market incentives to reduce certain types of pollution.52

Nonutilities are also able to put advanced generators

into operation quickly, sometimes as an alternative to

utility capacity that is already built.

The banking industry and telecommunications industry

have been discussed as points of comparison for the first

factor, the changing climate of economic and regulatory

thinking. The following sections analyze the more quantifiable factors that are motivating the structural changes

in the electric power industry&price differences and

technological advances. The analyses include EIA data

to measure these factors where they are relevant.

Price Differences

While restructuring originated with the Public Utility

Regulatory Policies Act of 1978, large differences in the

retail prices of electricity have continued to motivate

some to advocate expanded restructuring. The current

structure of the electric power industry, as mentioned

above, provides only a limited number of retail electricity customers&mostly in Pennsylvania, California,

Massachusetts, Oregon, and Washington&with the

opportunity to purchase electricity from alternative

suppliers. Further restructuring of the industry holds the

possibility of allowing more choice for more consumers.

Many industrial companies, because they are large

consumers of electricity and have a lot to gain if they can

reduce their average price of electricity by choosing

another provider, are especially prone to advocate

further restructuring. They argue that price differentials

among utilities provide an advantage to the competitor

who is situated in an area with lower electricity prices,

and that all consumers should have access to cheaper

electricity. Some industrial consumers, who have

threatened to purchase power from lower-priced providers, move the location of their companies, or generate

their own electricity, often have “succeeded in wringing

lower prices from their traditional electric utilities.”53

In the United States, the average revenue received per

unit of electricity sold, i.e., the price to all retail

consumers, varies substantially by State (Figure 24). In

1998, the States with average prices of more than 9.5
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 43

54 Both numbers are in nominal units. 55 Because industrial consumers usually use larger amounts of electricity than other consumers, and because they usually take it at

higher voltages, the cost of providing each unit of electricity to them is lower. 

MA

WA

4.03

4.90

5.16 5.76

4.80

4.02

5.95

6.07

5.43

6.26

5.70

5.30

6.08

5.71

6.28

6.04

5.44

5.34 6.38

10.17

9.83

11.93

9.59

10.30

5.78

5.78

5.62

5.98

4.16

5.56

5.07 5.88

5.53

6.45

6.99

6.88

6.40

7.01

OR

UT

MT

ID

CO

WY

4.31

ND

NE

KS

IA

MO

KY

WV

LA

SD

NV

AR

TX

FL

OK

MN

WI

IN OH

VA

MS AL

GA

SC

NC

TN

NH

VT

NJ

CT

RI

MD

IL DE

7.46

7.86

PA

MI

7.09

DC

7.41

7.33 6.78

AZ NM

CA

9.03

Cents per kWh

AK

9.97

HI

11.56

NY

10.71

ME 

9.75

U.S. Total Average Revenue per kWh in 1998 was 6.74 Cents

0-4.99

5.00-5.99

6.00-6.99

Over 7.00 

9.58

Figure 24. Average Revenue per Kilowatthour for All Sectors by State, 1998

 kWh = Kilowatthour.

 Note: The average revenue per kilowatthour of electricity sold is calculated by dividing revenue by sales. Sales in deregulated

retail electricity markets are not included.

 Source: Energy Information Administration, Form EIA-861, “Annual Electric Utility Report.”

cents per kilowatthour were the six New England States,

New York, New Jersey, Alaska, and Hawaii. Since the

1996 edition of this report, the average revenue from

electricity sales to all consumers in the United States has

declined from 6.9 cents per kilowatthour to 6.7 cents per

kilowatthour.54 It is not coincidental that many of the

States leading the restructuring movement are among

the States with high prices. They see restructuring as a

means of lowering prices. In contrast, States with

average prices below 6 cents per kilowatthour are still

scattered throughout the country. Most have average

prices for all consumers that are less than one-half those

in States with the highest average revenue. These States

have less incentive than the higher-cost States to

restructure their electricity markets. A similar geographic pattern exists for average electricity prices

received from industrial consumers, although industrial

consumers yield one-third lower average revenues than

all retail customers (Figure 25).55

Large industrial electricity consumers typically pay less

because it is less costly to service one large customer

than many small ones. With this power, industrial

consumers have played a substantial role in motivating

the restructuring of the electric power industry. Their

bargaining power is reflected in the declining trend of

industrial prices relative to those paid for all consumers

(Figure 26). The relative price industrial consumers paid

for electricity rose from the mid-1960s until 1983, then

declined from 1983 through 1997, then rose slightly in

1998, but not to the level it had been in 1996. Because

real average revenues from both groups have been

falling since 1983, the relatively lower revenues for

industrial consumers indicate that their average price

has been falling faster than the average price charged to

all consumers.

Over the years, utilities have developed programs to

help lower the price of electricity to the industrial sector.
44 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

56 H.R. Linden, “The Revolution Continues,” The Electricity Journal (December 1995), p. 54.

MA

WA

2.64

3.50

3.45

4.57

3.19

2.77

4.34

3.94

3.65

4.44

4.30

3.60

4.43

4.45

4.46

3.99

3.86

4.30 3.95

7.94

7.27

9.42

8.18

7.70

4.15

4.16

4.17

4.22

2.91

3.89

3.78 3.82

3.69

4.63

4.14

4.65

4.23

4.81

OR

UT

MT

ID

CO

WY

3.38

ND

NE

KS

IA

MO

KY

WV

LA

SD

NV

AR

TX

FL

OK

MN

WI

IN OH

VA

MS AL

GA

SC

NC

TN

NH

VT

NJ

CT

RI

MD

IL DE

5.11

5.63

PA

MI

5.03

DC

4.38

5.12 4.47

CA

6.59

Cents per kWh

AK

7.17

HI

9.41

NY

4.95

ME 

6.61

U.S. Total Industrial Average Revenue per kWh in 1998 was 4.48 Cents

0-3.99

4.00-4.99

5.00-5.99

Over 6.00 

7.61

AZ NM

Figure 25. Average Revenue per Kilowatthour for the Industrial Sector by State, 1998

1960 1965 1970 1975 1980 1985 1990 1995

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0

Figure 26. Relative Average Revenue of

Electricity Sales: Ratio of Industrial

Consumers to All Consumers,

1960-1998

 Source: Energy Information Administration, Annual Energy

Review 1998, DOE/EIA-0384(98) (Washington, DC, July

1999), Table 8.13.

 kWh = Kilowatthour.

 Note: The average revenue per kilowatthour of electricity sold is calculated by dividing revenue by sales. Sales in deregulated

retail electricity markets are not included.

 Source: Energy Information Administration, Form EIA-861, “Annual Electric Utility Report.”

They traditionally have relied on alternative rate design

approaches, such as interruptible service and time-of-use

rates to reduce the time-variation of demand by the

industrial sector. The programs also use technological

approaches, such as thermal storage. A number of

utilities have developed flexible custom measure programs, which allow industrial energy users and utilities

to work together to identify cost-effective programs.

Technological Advances

Restructuring has been sustained primarily by technological improvements in gas turbines. “In areas with

cheap< natural gas&most notably the United States&gas

turbines [are] the least cost option [for new electricity

generating capacity].56 These improvements also have

recast economies of scale in electric power generation

technologies. No longer is it necessary to build a 1,000-

megawatt generating plant to exploit economies of scale.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 45

57 R.E. Balzhiser, “Technology - It’s Only Begun to Make a Difference,” The Electricity Journal (May 1996). 58 Energy Information Administration, Inventory of Nonutility Electric Power Plants in the United States 1998, DOE/EIA-0095(98)/2

(Washington, DC, December 1999), p. 7 and EIA, Inventory of Electric Utility Power Plants in the United States 1999, DOE/EIA-0095(99)

(Washington, DC, November 1999), p. 11. 59 Energy Information Administration, Annual Energy Outlook 2000, DOE/EIA-0383(2000) (Washington, DC, December 1999), p. 233. 60 Energy Information Administration, AEO2000 National Energy Modeling System run AEO2K.D100199A. 61 Remarks of Jay Hakes, Administrator, Energy Information Administration, North American Gas Strategies Conference (Calgary,

Alberta, October 19, 1998). 62 Energy Information Administration, Assumptions to the Annual Energy Outlook, DOE/EIA-0554 (Washington DC, January 2000), Table

37, Cost and Performance Characteristics of New Central Station Electricity Generating Technologies. 63 H.R. Linden, “Operational, Technological, and Economic Drivers for Convergence of the Electric Power and Gas Industries,” The

Electricity Journal (May 1997).

Table 7. Total Projected Additions of Electricity

Generating Capability for Electric

Generators by Technology Type, 

1999-2020

(Gigawatts)

Technology Capability Additions

Coal Steam ............... 21.1

Combined Cycle ........... 135.2

Combustion Turbine/Diesel . . . 133.8

Fuel Cells . . . . . . . . . . . . . . . . 0.1

Renewable Sources ......... 9.7

Total .................... 299.9

 Source: Energy Information Administration, AEO2000

National Energy Modeling System run AE02K.D100199A.

Combined-cycle gas turbines reach maximum efficiency

at 400 megawatts, while aero-derivative gas turbines can

be efficient at scales as small as 10 megawatts.57 Indeed

from 1996 through 1998, gas-fired and gas- and oil-fired

capacity brought on-line was almost two-thirds of the

total. The average capacity of these units was 65 megawatts.58

In its modeling of the electric power industry, the

Energy Information Administration (EIA) compares the

estimates of the costs of different generating technologies. In its forecasts, “it is assumed that the selection

of new plants to be built is based on least cost, subject to

environmental constraints.”59 The reference case forecast

released by EIA in late 1999 projects that, of the 300 gigawatts of new generating capability projected to be added

by electric generators between now and 2020, 90 percent

will be either combined-cycle or combustion turbine

technology (Table 7)60 as nonutilities move toward less

capital intensive projects.61 Both technologies are

designed primarily to supply peak and intermediate

capacity but combined-cycle technology can also be used

to meet baseload needs. The reduction in baseload

nuclear capacity also has an impact on the electricity

outlook after 2010. Almost half of the new combined-cycle capacity projected over the entire forecast

period is expected to be brought on line in those 10

years, due in part to nuclear retirements. Another

relative advantage of combined-cycle technology as a

source of baseload capacity is the shorter leadtime

needed for construction.

Both advanced and conventional combined-cycle technologies require only 3 years while a coal or nuclear

plant needs 4 years.62 H.R. Linden writes in The

Electricity Journal that “under pressure of competition,

the all-in cost of a combined-cycle plant has dropped to

$450 per kilowatt, less than half that of a new clean coal

plant. In combined-cycle configurations, heat rates have

dropped. This has made natural gas at $2.50/million Btu

competitive with coal in terms of variable cost when the

much lower non-fuel operating and maintenance costs of

gas are figured in.”63

The following chapter outlines the major issues that are

framing the current debate over Federal initiatives to

facilitate the industry’s transition to a competitive

market environment.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 47

64 While each of the States have examined retail competition and most of them have taken steps toward that end, there is a consensus

among many interested parties that there must be a Federally guided transition to competition to ensure reliability of the national grid. 65 In the House of Representatives, legislation dealing with electricity deregulation is introduced and referred to the Energy and Power

Subcommittee, chaired by Congressman Joe Barton (R-TX). Once this Subcommittee has marked-up a bill, it is passed on to the full

committee, the Committee on Commerce, chaired by Congressman Tom Bliley (R-VA). In the Senate, legislation dealing with electricity

deregulation is introduced and referred to the Subcommittee on Water and Power, chaired by Senator Slade Gorton (R-WA) then passed

on to the full committee, the Energy and Natural Resources Committee, chaired by Senator Frank Murkowski (R-AK). 66 In early 1999, the Administration submitted to Congress a comprehensive restructuring proposal entitled “The Comprehensive

Electricity Competition Act.” It was introduced by Senator Frank Murkowski (R-AK) on May 13, 1999. See Appendix C for a summary. 67 Refer to Appendix C for details on S. 2071, “The Electric Reliability 2000 Act,” introduced by Senator Slade Gorton (R-WA). 68 “Senate Panel Abandons Restructuring Legislation; Approves Reliability Bill,” Public Power Daily (June 21, 2000). 69 This bill is H.R. 2944, “The Electricity Competition and Reliability Act of 1999,” introduced by Congressman Joseph Barton (R-TX)

on September 24, 1999. See Appendix C for a summary.

6. Federal Legislative Initiatives

Introduction

Even with the changes that have been spurred by the

factors discussed in the previous chapter, there are still

statutory and regulatory limitations at both the Federal

and State levels64 on how quickly and how far restructuring can proceed. This chapter examines the restructuring initiatives of the U.S. Congress. A number of bills

were introduced in the 106th Congress as well as in the

past two Congresses which dealt with the deregulation

of the electricity industry. Hearings, debates, and panels

were held to determine the issues that must be

addressed and decided. All groups associated with the

electric power industry have been given a chance to be

heard. As of July 1, 2000, 18 legislative proposals dealing

with the electric power industry were pending in the

House of Representatives and 13 in the Senate.65 Some of

these bills addressed all of the issues surrounding the

restructuring of the industry and are considered “comprehensive” legislation. Others addressed several closely

related issues and still others concentrated on just one of

the issues, for example bulk power reliability or taxexempt financing by governmentally owned utilities.

The latter have come to be known as “stand-alone”

restructuring legislation. Stand-alone proposals receive

strong support among some groups because they believe

that this type of legislation can move through the legislative process quickly while others contend that this is a

short-sighted and unsatisfactory “piece-meal” approach.

The Clinton Administration has been pressing Congress

to reach consensus and enact comprehensive legislation

without further delay.66 The Administration has stressed

that more delays will result in a significant decrease in

the reliability of the Nation’s supply of power due to the

ever-increasing demand for electricity coupled with the

fact that needed investments in new generating capacity

are being stymied due to investors’ uncertainties during

the industry’s transition. The Administration had also

made it known that, although reliability is at the

forefront of the critical issues, they were not in support

of a stand-alone bill that addressed reliability. However,

some committee members stressed the necessity of such

action if a workable comprehensive proposal could not

be ironed out quickly. Consequently, the Senate Energy

and Natural Resources Committee came to a decision in

late June, 2000 to end their pursuit of comprehensive

restructuring legislation because it was unlikely that it

could be promulgated before the current Congress ends.

Instead, they unanimously reported the stand-alone

reliability legislation introduced by Senator Slade Gorton

(R-WA).67 This bill “. . .would pave the way for FERC to

designate the North American Electric Reliability Organization . . . as the developer and enforcer of electric

reliability standards in the United States, under Federal

Energy Regulatory Commission (FERC) supervision. The

Committee approved the bill with an amendment that

reflects industry consensus on State vs. Federal jurisdiction over reliability.”68

On the House of Representatives side, Commerce Committee members have stated that they are still hoping to

move ahead with a full-committee mark-up of a comprehensive bill before the end of this year’s session.69 This

bill was the only comprehensive proposal to move

forward in the 106th Congress. The reason for this
48 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

seeming lack of progress can be attributed to the fact

that reaching compromise and consensus on the number

of issues involved in restructuring the electric power

industry is a monumental task. The inset box above lists

the major issues that have been considered and debated.

Underlying each of these issues are complex details

which must be addressed. In addition, the pro and con

arguments of a vast number of stakeholders with

diverse interests have been heard and must be taken into

account. The committee members themselves have been

divided on various issues and must make decisions that

will benefit not only the national economy and the

industry, but also their varied constituencies. For

instance, members who represent States or districts that

already enjoy lower than average rates for electricity are

concerned that certain actions, which may benefit the

Nation as a whole, could result in an increase in rates for

their electorate.

Major Issues Under Debate

The following paragraphs detail several of the more

controversial of the issues mentioned above (reliability,

regional transmission organizations, a renewable portfolio standard, and repeal of the Public Utility Holding

Company Act of 1935 ( PUHCA) and the Public Utility

Regulatory Policies Act of 1978 (PURPA)) followed by a

synopsis of the Clinton Administration’s Comprehensive

Electricity Competition Plan.

Reliability

Voluntary compliance by electric utilities with procedures for ensuring the reliability of the power system,

which were established by the North American Electric

Reliability Council (NERC) and its member Regional

Reliability Councils, has worked effectively over the past

three decades. However, with the emergence of competition and the multitude of changes taking place in the

industry over the past few years, industry leaders and

government officials are concerned that the reliability of

the system may be threatened. Many officials believe

that a voluntary approach is no longer adequate, and

that Federal legislation establishing mandatory reliability rules is required to ensure that competition does

not compromise the reliability of the transmission

system. A number of House and Senate bills contain

provisions that would lead to mandatory reliability

standards for electric utilities to follow.

Administration and enforcement of mandatory reliability standards is also an issue. One approach suggested

in pending Federal legislation, would be to create an

independent reliability organization, such as NERC,

with FERC having some sort of oversight responsibility

Major Electric Power Industry Restructuring Issues Before Congress

 Mandatory participation in a regional transmission organization (RTO)

 Bulk power reliability

 Nuclear decommissioning provisions

 Transmission expansion and construction

 Reform of the Tennessee Valley Authority and Federal power marketing administrations

 Federal authority to regulate retail sales, protect retail consumers, or regulate local grid interconnections

 Utility mergers

 Public benefits fund

 Retail net metering

 Emissions caps and standards for generators

 IRS restrictions on “private use” of municipal electric systems

 State/Federal jurisdiction clarification

 Retail sales to Federal agencies

 Retail reciprocity

 Extension of Order 888 wholesale wheeling rules to transmission by municipals, cooperatives, Federal power

marketing administrations, and the Tennessee Valley Authority

 Renewable portfolio standards

 Repeal of PUHCA and Section 210 of PURPAa

 aRepeal of PUHCA and Section 210 of PURPA are discussed in more detail later in this Chapter.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 49

70 Copies of the Report of the U.S. Department of Energy’s Power Outage Study Team: Findings and Recommendations to Enhance Reliability

from the Summer of 1999 are available from DOE’s Office of Public Inquiries, (202) 586-5575, and on the Internet at

www.policy.energy.gov/electricity/postfinal.pdf.

for establishing the reliability standards. The appropriate role of the States in establishing and enforcing

standards is also an issue. State regulators want to

maintain some control over the quality of service

received by customers in their respective States. Federal

legislation dealing with reliability will have to address,

in some manner, the appropriate organization structure

for enforcing reliability standards, and jurisdictional

authority between Federal and State regulators.

In August of 1999, Secretary of Energy Bill Richardson

formed DOE’s Power Outage Study Team. The Team’s

purpose was to study significant electric power outages

and other disturbances that occurred across the Nation

during the summer of 1999 and to recommend

appropriate Federal actions to avoid electric power

disturbances in the future. The first step was to meet

with relevant utilities, independent system operators,

and regulators in areas where outages and disturbances

occurred. The Team’s findings were published in an

Interim Report issued in January 2000. Subsequently,

three workshops were held to solicit recommendations

from electric industry stakeholders on possible

approaches to address the issues raised by the Team’s

findings. A Final Report was given to the Secretary on

March 13, 2000, containing the Team’s findings along

with 12 recommendations for Federal lawmakers.

Secretary Richardson stressed that “Congress must

move ahead to make changes in the Federal statutory

framework to provide the certainty that is needed to

achieve reliable electric service in competitive wholesale

and retail markets.”70

Regional Transmission Organization Issues

In December 1999, FERC released Order 2000 calling for

the voluntary formation of regional transmission organizations (RTOs). FERC believes that RTOs will facilitate

the continued development of competitive wholesale

power markets and will lead to improvements in

reliability and management of the transmission system.

(Chapter 7 has a detailed discussion of Order 2000). In

order for an RTO to be fully effective, all of a region’s

transmission system must be controlled by the RTO. Its

effectiveness and the benefits cannot be achieved if

portions of the transmission system are left out.

Although voluntary participation in RTOs was requested, FERC has determined that it has the authority

under Sections 205 and 206 of the Federal Power Act to

order public utilities, primarily investor-owned utilities,

to participate in RTOs on a case-by-case basis, if necessary, to remedy undue discrimination or anticompetitive

activities of electric utilities. FERC believes that Federal

legislation is needed to reinforce the Commission’s

authority to order public utilities to participate in an

RTO, if the voluntary approach does not succeed. The

above authority refers primarily to investor-owned

utilities. To cover the entire transmission grid, FERC

also needs similar authority with respect to municipal

electric utilities, rural cooperatives, and Federally owned

utilities. 

Renewable Portfolio Standard

There have been a number of proposals for a renewable

energy portfolio standard. Such a standard would

require that any company selling electricity in a competitive market include some amount of renewable

energy as part of its portfolio of generating fuels. The

portfolio standard would more or less be competitively

neutral, i.e., it would have to impose an equal obligation

on any company selling electricity in any State. 

Definitions would have to be made regarding which

renewable resources were eligible. For instance, the

Clinton Administration does not include hydroelectricity

in the renewable portfolio section of its restructuring

proposal. Purchase requirements would have to be

decided upon, and the level of the standard needs to be

determined. In addition, enforcement of the standard

would have to be addressed as well as penalties for

failure to meet the standard. 

The main differences among the various renewable

portfolio standards proposals are the required renewable share, the timing of the program, the definition of

qualifying facilities, and whether or not there is a limit

(cap) on the allowable price for renewable credits. For

example, the Administration’s proposed Comprehensive

Electricity Competition Act, submitted to Congress on

April 15, 1999, includes a Federal renewable portfolio

standard that would apply to all U.S. electricity

suppliers. The key provisions of the Act that pertain to

a renewable portfolio standard are:

 The required renewable share of electricity sales

would be set at 2.4 percent for the years 2000 to

2004, increase to 7.5 percent by 2010, and then
50 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

71 For information regarding EIA’s examination of the potential impacts of these proposed provisions, refer to Annual Energy Outlook

2000, DOE/EIA-0383(2000) (Washington, DC, December 1999), p. 18.

72 For a discussion of these abuses, refer to Chapter 4. 73 For further discussion of these changes, see Energy Information Administration, The Public Utility Holding Company Act of 1935: 1935-

1992, DOE/EIA-0563 (Washington, DC, January 1993), p. 23.

remain at 7.5 percent through 2015, after which it

would expire (sunset).

 Qualifying renewables would include geothermal,

biomass (including biomass used in coal-fired

plants), solar thermal, solar photovoltaic, wind,

and the portion of municipal solid waste (MSW)

that consists of biomass products. 

 The price for renewable credits would be capped

at 1.5 cents per kilowatthour. If the market price

for the credits rose above the cap, electricity

retailers would be able to purchase credits from

the U.S. Department of Energy (DOE) at the 1.5-

cent price (with the resulting revenues deposited

in a Public Benefits Fund). In that event, the

qualifying renewable share actually achieved

would fall below the required 7.5-percent share.71

Critics believe that a renewable portfolio standard will

increase costs to consumers. They also argue that

customers and the market should be able to select what

types of electricity sources are used rather than be

mandated to select one over another. These critics also

say that promulgating a portfolio would also provide an

unfair market advantage to renewable energy technologies. However, supporters argue that the portfolio

standard would help diversify the Nation’s energy

supply and would promote environmentally-benign

forms of electricity. Supporters further argue that

fledgling renewable energy industries would receive a

much-needed boost with an increased market demand

for renewables. 

Repeal of PUHCA

Although the relevancy of PUHCA’s provisions are in

question today due to the current transitional state of the

electric power industry, there is little question that 6

decades ago PUHCA achieved what it was designed to

do&break up large, powerful trusts that abused their

powers over the Nation's electric and gas distribution

networks. However, in today's environment of

increasing electric industry competition, there are those

who believe that PUHCA's regulations are antiquated

and are now impeding the transition to competition.

Conversely, others believe strongly that, until the

industry completes the transition, PUHCA's regulations

must stay in effect in order to protect consumers. 

Over the years, the petition for PUHCA repeal has, for

the most part, been based on two arguments&that

PUHCA has already achieved its goal of restructuring in

order to make holding companies manageable and regulated, and that it has been rendered obsolete because of

changes that have occurred in the latter part of this

century which preclude the holding company abuses of

yesterday.72 They are as follows:

 The development of an extensive disclosure

system for all publicly held companies

 The increased competence and independence of

accounting firms

 The development of accounting principles and

auditing standards and the means to enforce them

 The increased sophistication and integrity of

securities markets and securities professionals

 The increased power and ability of State regulators.73

Supporters of stand-alone PUHCA-repeal legislation

believe that speedy passage is of utmost importance,

given the rapidly changing makeup of the electric

industry. They contend that the current PUHCA

provisions prevent all companies from competing on a

level playing field, which some believe is a necessity in

a competitive market. Under the prevailing law, the SEC

imposes the business and financial restrictions which

companies feel are unfair in the current changing

environment. The major restrictions include the following: prices for wholesale and retail transactions are

set by FERC and State utility commissions, respectively;

registered holding companies need SEC approval to own

electric and gas operations; mergers and acquisitions

require regulatory approval; and the types of businesses

in which registered holding companies may engage

are severely limited, although exempt wholesale generators (EWGs) do not have the same limitations. While

other comprehensive energy legislation that has been

introduced contains provisions to repeal PUHCA along

with provisions aimed at addressing other restructuring

issues, certain interests feel that such comprehensive

proposals will take far too long to move through the

system. They argue that repeal of PUHCA must be

promulgated now through stand-alone legislation.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 51

74 For a discussion of the events that led to PURPA and how it affected the industry, refer to Chapter 4. 75 Energy Information Administration, Renewable Energy Annual 1995, DOE/EIA-0603(95) (Washington, DC, December 1995), pp. xxvixxvii.

Those who are against outright repeal of PUHCA are not

arguing that the Act should remain in effect in an open

market atmosphere. Rather, they believe that the time is

not yet quite right for its repeal. Until the Nation has

completed the transition to a fully competitive market,

the safeguards that PUHCA provides are necessary.

They question the wisdom of removing vital consumer

protection mechanisms and leaving the door open to

anticompetitive practices by monopolies which are at

present aggressively taking actions, such as merging and

diversifying, perhaps to increase their market dominance. Most opponents of the legislative proposals to

repeal PUHCA stress that what they are against is

immediate, stand-alone action. Instead, they want to see

well-thought-out, comprehensive restructuring legislation that will deal with all deregulation issues,

including repeal of PUHCA. 

Repeal of PURPA

PURPA was born of the energy crises of the 1970s,

which resulted in an intense desire by Congress to

reduce the Nation's dependence on foreign oil (and fossil

fuels in general) and to diversify the technologies used

for electricity generation. PURPA's goal was to cultivate

conservation and the efficient use of resources.74 It was

successful in that it promoted cogeneration, the use of

renewable resources, and other energy-efficient technologies, and it was fortuitous in that it also introduced

competition by demonstrating that the generation of

electricity is not a natural monopoly. But, like PUHCA,

PURPA is now being targeted for repeal due to the

industry's move to competition. There are many arguments on both sides of the debate over the prudence of

eliminating PURPA immediately, eventually, or not

at all.

Proponents of stand-alone PURPA-repeal legislation

contend that the Act’s mandatory purchase obligation is

grossly anticompetitive and anticonsumer&anticompetitive because the Government created an artificial

market by mandating that utilities buy from QFs, and

anticonsumer because numerous studies have estimated

that the Act caused utilities (and ultimately, consumers)

to pay billions of dollars over present market prices for

power. They claim that, although the Act introduced

competition, it can hardly be said that it did so in an

atmosphere of free market participation, a basic tenet of

economic theorists who stress that the rules and prices

must be established by the market¬ by the Government. In addition they assert that, because of EPACT’s

creation of EWGs and its incorporation of competitive

policies, PURPA’s QF concept has been overtaken by

events, i.e., the industry now realizes that nonutilities

can cleanly and efficiently provide additional generating

capacity.

Those who want PURPA eliminated now say that its

mandatory purchase clause is anticompetitive and is

therefore impeding the transition to competition. Furthermore, QFs have been receiving long-run avoidedcost rates that today substantially exceed current market

prices. These rates were based on past forecasts of

sharply rising oil and natural gas prices as well as the

expectation of future increases in the demand for

electricity and construction of new generating capacity.

By the late 1980s and early 1990s, however, oil prices

had stabilized, natural gas prices had declined, and

excess generating capacity in most regions of the country

allowed utilities to buy capacity and energy at much

lower prices than had been forecast a decade earlier. The

utilities' actual avoided costs dropped lower than in the

mid-1980s and were considerably lower than the levels

required by the long-term contracts imposed by some

State Commissions. Many utilities contend that PURPA

has caused dramatic hikes in retail electric rates, and

many groups along with these utilities now believe that

new regulatory action must be taken to correct past

misjudgments.75

Forecasters predict that future power generation will be

dominated by natural gas. Reformers argue that, based

on these forecasts, PURPA becomes irrelevant because

natural gas-fired power generation is relatively inexpensive and the most environmentally benign of all the

fossil fuels used in electric power generation. As

mentioned earlier, some groups contend that PURPA is

no longer necessary because its goals have already been

achieved&i.e., cogeneration using improved turbine

techniques and the use of renewable resources has not

only gotten a foothold but has claimed a rather

significant share of electric power production. Proponents of repeal further contend that PURPA's

environmental and fuel diversification goals will be

maintained by the workings of a free market while

others are not so sure. Although they may agree that a

free market can provide a solution to many of the

industry's problems, they seriously question the wisdom
52 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

76 This is related to the concept of “sustainable development,” which refers to ways of social, economic, and political progress that meet

the needs of the present without compromising the ability of future generations to meet their needs. Sustainable development points to

ways that the economy can continue to develop without compromising the environment. 77 U.S. Department of Energy, Comprehensive Electricity Competition Plan (Washington, DC, March 1998). 78 Adopted from the fact sheet issued by the Department of Energy on the Comprehensive Electricity Competition Plan (April 15, 1999).

of relying on competition to continue the strides made in

the use of renewables and cogeneration techniques.

Energy conservation and diversification of generating

fuels were mandated by Congress because of the

growing dependence on foreign oil and the Nation's

concerns about the energy crises of the 1970s. Those

fears have faded with the passage of time, but it is

argued that it is not out of the realm of possibilities that

another crisis could occur. Indeed, some believe that it

would be shortsighted and irresponsible to regard

energy shortages as merely nightmares of the past and

to gamble on the unlikelihood of a similar recurrence.

They argue that the Nation cannot be without the ability

to cope with such a situation in the future.

Even if dependence on foreign energy sources was not

an issue, PURPA supporters stress that common sense

dictates that energy be conserved and that electricity

generation use more environmentally benign fuels in

order to sustain a certain quality of life for future

generations.76 In addition, some believe that QF policy

corrects a market failure&i.e., the price of fossil or

nuclear energy is too low based on the costly damage it

does to the environment and the fact that those who

create the pollution do not pay for it. In this context,

some argue that conservation, diversification of fuels,

and the use of renewable resources that are not

depletable and other fuels that lessen the problems of

acid rain and greenhouse gases must continue to be

supported.

In addition to PURPA's merits regarding the environment and fuel diversification, its supporters point

out that QFs bring increased reliability while decreasing

the need for large, costly plants. They contend that

today's utilities have too much market power, which

makes it necessary for PURPA to continue to give

nonutilities a competitive advantage, and until every

electricity generator is playing on a level field, PURPA's

QF provisions are justified.

There are also those who believe that, while PURPA repeal might be warranted in a competitive electricity

supply scenario, such a scenario has not been realized

yet. Just as some PUHCA reformers are against immediate piecemeal and stand-alone action, some PURPA

reformers believe that repeal should be included in a

comprehensive restructuring bill. They argue that there

is no need to push a stand-alone repeal bill through

Congress when there is currently other proposed electricity competition legislation that will comprehensively

address the restructuring and regulatory issues that

warrant legislative action, including repeal of PURPA.

The Administration’s

Comprehensive Electricity

Competition Proposal

The Administration released its revised version of the

Comprehensive Electricity Competition Plan in April

1999. The 1999 Plan closely mirrors the Administration’s

1998 proposal.77 Both are built on the premise that a

competitive electric energy market will lower prices,

encourage innovation, and allow customers a choice in

electric energy suppliers. The Administration’s Plan also

aims to promote a clean environment, increase the

reliability of the national power supply grid, and to aid

low-income consumers, rural communities, and Indian

tribes.78

Several issues that were not adequately developed in the

1998 Plan have since been included in the 1999 Plan.

These are:

 Improving prospects for competition in regions

served by the Tennessee Valley Authority, the

Bonneville Power Administration, and other

Federal Power Marketing Administrations

 Encouraging the use of environmentally friendly

and reliable technologies

 Enhancing consumer protection

 Enhancing the reliability of our electric system

 Providing support for Indian tribes and consumers

in those areas

 Increasing environmental benefits 

 Addressing the impact of competition on potentially affected electricity workers.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 53

79 Adopted from the fact sheet issued by the Department of Energy on the Comprehensive Electricity Competition Plan (April 15, 1999). 80 Slamming is a term used to describe changing a customer’s service provider without his or her permission. 81 Cramming is a term used to describe the inclusion of charges on a customer’s bill for services he or she never ordered, authorized,

received, or used.

The Comprehensive Electricity Competition Plan:79

 Supports customer choice through a flexible mandate that would require each utility to permit all

its retail customers to purchase power from the

supplier of their choice by January 1, 2003. States

or unregulated utilities could opt out if they find

that consumers would be better served by an

alternative policy or the current monopoly system.

This approach strikes a balance between the need

to spur competition and the tradition of determination of retail electricity policy by States.

 Endorses the principle that utilities should be able

to recover prudently incurred, legitimate, and

verifiable retail stranded costs that cannot be

reasonably mitigated (including assistance for

displaced workers). States and non-regulated

utilities would continue to determine stranded

cost recovery under State laws. The Plan grants

FERC “backup” authority to establish a stranded

cost recovery mechanism if the State lacks the

authority to provide such recovery due to constitutional constraints or jurisdictional gaps.

 Stipulates critical consumer protection initiatives

by: (1) requiring all electricity suppliers to publicly

disclose information on price, terms, and conditions of their offerings; the type of generation

source; and generation emission characteristics; (2)

granting all consumers access to competitive retail

service; (3) precluding possibilities of “slamming”80

and “cramming;”81 and (4) permitting customers to

aggregate their loads.

 Repeals substantive requirements of PUHCA.

Provides States and FERC with additional access

to books and records of holding companies to

assist regulatory authorities in guarding against

inter-affiliate abuses.

 Establishes FERC’s jurisdiction over mergers/consolidations of electric utility holding companies

and generation-only companies, and directs FERC

to examine the impact of mergers on the competitiveness of retail markets.

 Authorizes FERC to remedy market power in

wholesale markets and further accords the Commission “back up” market power remedies,

including ordering divestiture of assets in cases

where States lack necessary authority to remedy

retail market power.

 Recommends that the Federal Power Act (FPA) be

amended to require FERC to approve the formation of and oversee an organization that prescribes

and enforces mandatory reliability standards. 

 Creates an Electricity Outage Investigation Board

to investigate major electricity outages and report

its findings to the Secretary of Energy.

 Recommends that the Secretary of Energy be permitted to convene joint Federal/State meetings to

consider transmission capacity additions.

 Recommends amendments to the FPA to provide

FERC with the authority to require transmitting

utilities to turn over the operational control of

their transmission facilities to an independent

regional system operator (who should also have

planning and reliability responsibility).

 Secures the future of renewable generation

through the establishment of a Renewable Portfolio Standard (RPS) to require that 7.5 percent of

annual electricity sales be generated from nonhydroelectric renewable sources by 2010. This

requirement ends in 2015. The Plan repeals the

“must buy” provisions of PURPA, but preserves

existing contractual obligations.

 Encourages and supports continued funding of

public benefit programs by creating a $3 billion

Public Benefits Fund to provide matching funds

for States for low income assistance, energy

efficiency and renewables programs, consumer

education, and the development and demonstration of emerging renewables technologies. 

 With a view to promote renewables, recommends

that consumers should be eligible for net metering

with respect to very small renewable energy

projects.

 Recommends that Indian tribes be assisted to

participate in the new electricity markets and that

an Office of Indian Energy Policy and Programs be

established to evaluate various options in a

changing market environment.
54 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

82 As of May 1, 2000, three of these bills are at the forefront of Congressional attention. They are H.R. 2944 (which was the first and only

proposal to move out of the Subcommittee to the full Committee), S. 1047 (the Administration’s proposal), and S. 2098 (Senator

Murkowski’s proposal). 83 Bills that are not passed during the current Congress must be reintroduced in the next Congress. Of those which are reintroduced,

some will be amended while others may remain the same.

 Clarifies the authority of the Environmental Protection Agency to require a cost-effective interstate

trading system for nitrogen oxide pollutant reductions necessary to attain and maintain the National

Ambient Air Quality Standards for ozone.

 Ensures that Federal ownership of transmission

facilities does not hinder competition by modifying the governing rules of the Tennessee Valley

Authority and Federal Power Marketing Administrations.

 Aims to clarify Federal and State authority in

several areas. It aims to provide FERC with the

authority to order retail transmission, reinforces

FERC’s jurisdiction over unbundled retail transmission, and extends FERC’s authority over

municipals and cooperatives. The Plan exempts

Alaska and Hawaii from the provisions of the

Comprehensive Electricity Competition Act. 

 Eliminates private-use restrictions currently imposed on facilities using tax-exempt funds subject

to the requirement that tax-exempt financing not

be used for generation and transmission facilities

in the future. 

  Addresses nuclear decommissioning costs and

eliminates anti-trust review by the U.S. Nuclear

Regulatory Commission.

Conclusion

This chapter has examined Federal-level restructuring

actions taken by the U.S. Congress. Table 8 lists the bills

that have been introduced into the current Congress that

deal with one or more aspects of restructuring the

electric power industry.82 It is in chronological order (by

date of introduction) and begins with the House of

Representatives bills followed by the Senate bills.

Appendix D provides a summary of each.83 Further

details about the status of the proposals and statements

made by the committee chairmen, as well as the full text

of the bills, can be accessed through the Library of

Congress website at http://thomas.loc.gov. The

following chapter discusses additional Federal-level

initiatives&those taken by FERC concerning wholesale

power markets and restructuring the U.S. transmission

system. Subsequently, Chapter 8 analyzes State-level

activities and Chapter 9 looks at investor-owned utility

strategies, i.e., mergers, acquisitions, and divestitures.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 55

Table 8. Proposed Legislation Influencing the Restructuring of the Electric Power Industry Introduced

into the 106th Congress as of May 1, 2000

Bill Purpose/Sponsor

H.R. 341

Environmental Priorities Act of 1999

Establishes a “Fund for Environmental Priorities” to be funded by

a portion of the consumers’ savings resulting from retail electricity

choice, and for other purposes.

Introduced by Representative Robert Andrews (D-NJ) on January

19, 1999.

H.R. 667

The Power Bill

Clarifies State authority in matters involving retail wheeling,

reciprocity, and recovery of stranded costs, eliminates mandatory

purchase provisions contained within the Public Utility Regulatory

Policies Act of 1978, repeals the Public Utility Holding Company

Act of 1935, and for other purposes.

Introduced by Representative Richard Burr (R-NC) on February

10, 1999.

H.R. 721

Bond Fairness and Protection Act of 1999

Amends the Internal Revenue Code by restricting tax-exempt

bond financing by public power utilities, and for other purposes.

Introduced by Representative J.D. Hayworth (R-AZ) on February

11, 1999.

H.R. 971

Electric Power Consumer Rate Relief Act of 1999

Amends the Public Utility Regulatory Policies Act of 1978 to allow

State regulatory authorities to monitor rates charged by qualifying

facilities and to determine whether the facilities meet FERC

standards.

Introduced by Representative James Walsh (R-NY) on March 3,

1999.

H.R. 1138

Ratepayer Protection Act

Repeals Section 210 of the Public Utility Regulatory Policies Act.

Introduced by Representative Clifford Stearns (R-FL) on March

16, 1999.

H.R. 1253

A Bill to Amend the Internal Revenue Code of 1986

Amends the Internal Revenue Code to restrict the use of taxexempt financing by governmentally owned electric utilities and to

subject certain activities of such utilities to income tax.

Introduced by Representative Phil English (R-PA) on March 24,

1999.

H.R. 1486

Power Marketing Administration Reform Act of 1999

Provides for a transition to market-based rates for power sold by

the Federal Power Marketing Administrations and the Tennessee

Valley Authority.

Introduced by Representative Bob Franks (R-NJ) on April 20,

1999.

H.R. 1587

Electric Energy Empowerment Act of 1999

Amends the Federal Power Act to grant States the authority to

oversee and implement restructuring of the electricity industry,

repeals Section 210 of the Public Utility Regulatory Policies Act of

1978, repeals the Public Utility Holding Company Act of 1935, and

for other purposes.

Introduced by Representative Cliff Stearns (R-FL) on April 27,

1999.
Table 8. Proposed Legislation Influencing the Restructuring of the Electric Power Industry Introduced

into the 106th Congress as of May 1, 2000 (Continued)

Bill Purpose/Sponsor

56 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

H.R. 1828

Comprehensive Electricity Competition Act

Provides a comprehensive approach to restructuring the private

and public electricity industry and includes provisions to amend or

repeal the Public Utility Regulatory Policies Act of 1978, the

Federal Power Act, the Public Utility Holding Company Act of

1935, and for other purposes.

Introduced by Representative Thomas Bliley (R-VA) on May 17,

1999.

H.R. 2050

Electric Consumers’ Power to Choose Act of 1999

Provides a comprehensive approach to electricity restructuring,

aims to provide consumers with a reliable source of energy and a

choice of electric providers, and for other purposes.

Introduced by Representative Steve Largent (R-OK) on June 8,

1999.

H.R. 2363

The Public Utility Holding Company Act of 1999

Repeals the Public Utility Holding Company Act of 1935 and

enacts the Public Utility Holding Company Act of 1999 to provide

for continuing consumer protection by facilitating Federal and

State commission access to relevant books and records of all

companies in a holding company system.

Introduced by Representative W.J.(Billy) Tauzin (R-LA) on June

25, 1999.

H.R. 2569

Fair Energy Competition Act of 1999

Directs FERC to prescribe stricter air quality regulations,

establishes a National Electric System Public Benefits Board for

public purpose programs funded by a capped wires charge

assessed to each operator, creates a renewable energy portfolio,

amends the Public Utility Regulatory Policies Act of 1978, and for

other purposes.

Introduced by Representative Frank Pallone, Jr. (D-NJ) on July

20, 1999.

H.R. 2602

National Electricity Interstate Transmission Reliability

Act

Grants FERC jurisdiction over the creation and operation of an

Electric Reliability Organization (ERO) and authorizes FERC to

approve and enforce reliability standards for the bulk-power

system.

Introduced by Representative Albert Wynn (D-MD) on July 22,

1999.

H.R. 2645

Electricity Consumer, Worker, and Environmental

Protection Act of 1999

Establishes consumer protection mechanisms, addresses

stranded cost recovery, electric utility mergers, and standards for

a renewable energy portfolio. Requires utilities to transfer certain

assets to regulated counterparts or affiliates after deregulation of

electricity sales.

Introduced by Representative Dennis Kucinich (D-OH) on July 29,

1999.
Table 8. Proposed Legislation Influencing the Restructuring of the Electric Power Industry Introduced

into the 106th Congress as of May 1, 2000 (Continued)

Bill Purpose/Sponsor

Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 57

H.R. 2756

Fair Competition in Tax-Exempt Financing Act of 1999

Amends the Internal Revenue Code of 1986 to prevent tax-exempt

bonds from being used to finance public projects that will compete

with private enterprise.

Introduced by Representative Ralph Hall (D-TX) on September 15,

1999.

H.R. 2786

Interstate Transmission Act

Places unbundled transmission sold at retail under FERC

jurisdiction and allows FERC to determine State or Federal

jurisdiction for transmission and distribution facilities. Authorizes

FERC to review pricing policies and activities of transmission

service and allows for recovery of stranded costs.

Introduced by Representative Thomas Sawyer (D-OH) on August

5, 1999.

H.R. 2944

Electricity Competition and Reliability Act of 1999

Provides a comprehensive approach to restructuring the electricity

industry and includes provisions to amend or repeal the Public

Utilities Regulatory Policies Act of 1978, the Federal Power Act,

the Public Utility Holding Company Act of 1935, establish an

electric reliability organization, and for other purposes. 

Introduced by Representative Joseph Barton (R-TX) on

September 24, 1999.

H.R. 2947

Home Energy Generation Act

Removes barriers to net metering by amending the Federal Power

Act and imposes standards for net metering and interconnection to

the electric grid.

Introduced by Representative Jay Inslee (D-WA) on September

24, 1999.

S.161 

Power Marketing Administration Reform Act

Prescribes guidelines and sets operational requirements on the

Federal Power Marketing Administrations and the Tennessee

Valley Authority to assist as they transition to a competitive

market, and prescribes specifics regarding use of revenue

collected through market-based pricing.

Introduced by Senator Daniel Moynihan (D-NY) on January 19,

1999.

S. 282

Transition to Competition in the Electric Industry Act

Repeals Section 210 of the Public Utilities Regulatory Policies Act

of 1978 and allows for recovery of stranded costs.

Introduced by Senators Connie Mack (R-FL) and Bob Graham (DFL) on January 21, 1999.

S. 313

Public Utility Holding Company Act of 1999

Repeals the Public Utility Holding Company Act of 1935 and

enacts the Public Utility Holding Company Act of 1999, and for

other purposes.

Introduced by Senator Richard Shelby (R-AL) on January 27,

1999.
Table 8. Proposed Legislation Influencing the Restructuring of the Electric Power Industry Introduced

into the 106th Congress as of May 1, 2000 (Continued)

Bill Purpose/Sponsor

58 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

S. 386

Bond Fairness and Protection Act of 1999

Amends the Internal Revenue Code by eliminating restrictions on

public power utilities which impede their ability to provide open

access transmission, and restricts the ability of public power

utilities to use tax-exempt financing for construction of new

facilities.

Introduced by Senator Slade Gorton (R-WA) on February 6, 1999.

S. 516

Electric Utility Restructuring Empowerment and

Competitiveness Act of 1999

Benefits consumers by promoting competition in the electric power

industry, and for other purposes.

Introduced by Senator Craig Thomas (R-WY) on March 3, 1999.

S. 1047

Comprehensive Electricity Competition Act a

Provides a comprehensive approach to electricity restructuring

and includes provisions to amend or repeal the Public Utilities

Regulatory Policies Act of 1978, the Federal Power Act, and the

Public Utility Holding Act of 1935, and for other purposes.

Introduced by Senator Frank Murkowski (R-AK) on May 13, 1999.

S. 1048

Comprehensive Electricity Competition Tax Act

Amends the Internal Revenue Code with respect to tax-exempt

private activity bonds to declare that the determination whether

any electric output facility bond issued before enactment of this

Act is a private activity bond shall be made without regard to any

specified permissible competitive action taken by the issuer.

Introduced by Senator Frank H. Murkowski (R-AK) on May 13,

1999.

S. 1273 

Federal Power Act Amendments of 1999

Amends the Federal Power Act, facilitates the transition to more

competitive and efficient electric power markets, and for other

purposes.

Introduced by Senator Jeffrey Bingaman (D-NM) on June 24,

1999.

S. 1284

Electric Consumer Choice Act

Amends the Federal Power Act to include reciprocity provisions,

recognizes the State’s authority to regulate retail electric sales and

the local distribution of electric energy, repeals the Public Utility

Holding Company Act of 1935 and Section 210 of the Public

Utilities Regulatory Policies Act of 1978.

Introduced by Senator Don Nickles (R-OK) on June 24, 1999.

S. 1369

Clean Energy Act of 1999

Enhances the benefits of the national electric system by

encouraging and supporting State programs for renewable energy

sources, universal electric service, energy conservation and

efficiency, and for other purposes.

Introduced by Senator James Jeffords (R-VT) on July 14, 1999.

S. 1949

Clean Power Plant and Modernization Act of 1999

Sets emission standards for operating and future fossil fuel-fired

generating plants, and for other purposes.

Introduced by Senator Patrick Leahy (D-VT) on November 17,

1999.
Table 8. Proposed Legislation Influencing the Restructuring of the Electric Power Industry Introduced

into the 106th Congress as of May 1, 2000 (Continued)

Bill Purpose/Sponsor

Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 59

S. 2071

Electric Reliability 2000 Act

Benefits electricity consumers by promoting the reliability of the

bulk power system.

Introduced by Senator Slade Gorton (R-WA) on February 10,

2000.

S. 2098

Electric Power Market Competition and Reliability Act

Facilitates the transition to a more competitive and efficient electric

power market and ensures electric reliability.

Introduced by Senator Frank Murkowski (R-AK) on February 24,

2000.

 a

This is the Administration’s restructuring proposal.

 Source: Library of Congress website at http://thomas.loc.gov/.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 61

84 The transmission system is an interconnected group of lines and equipment for the movement or transfer of electric energy between

points of supply and points where it is transformed for delivery to customers or is delivered to other electric systems.

7. Wholesale Power Markets and Restructuring the

U.S. Power Transmission System 

Introduction

While congressional assent is necessary for many of the

reforms to the electric power industry, Congress has

granted the Federal Energy Regulatory Commission

(FERC) authority to make regulations in a number of

areas. The purpose of this chapter is twofold. First, it

highlights FERC initiatives to promote competitive

wholesale power markets over approximately the past

20 years, which have become progressively broader in

scope in recent years. Second, it highlights FERC’s

initiatives in promoting an efficient and reliable power

transmission system.84 The two areas&promoting competitive wholesale power markets and an efficient power

transmission system&are interrelated goals. Having

fully competitive power markets depends on creating an

efficient, well operating transmission system.

As mentioned in Chapter 3, the power transmission

system is one of three major components of the electric

power industry; the others are power generation and

distribution. The transmission system provides the

capability to move electrical power over long distances,

producing significant benefits to electric utilities and to

electricity customers. One benefit is that large efficient

power plants can be built far from where the power is

used, and the transmission system or systems can

deliver power from those plants to many customers over

a broad area at a relatively low cost. This capability was

one of the reasons that utilities built large centralized

power plants, which now provide most of the Nation’s

power generation capacity.

Another benefit of today’s transmission system is that it

provides wholesale electricity customers an opportunity

to purchase less expensive power from alternative

suppliers such as power marketers or independent

power producers. This opportunity, which did not exist

until the passage of the Energy Policy Act of 1992

(EPACT), and later expanded in 1996 by FERC’s Order

888, is the foundation for creating competitive wholesale

power markets.

As the electric power industry becomes more competitive, many of the changes taking place involve the

regulation, operation, and control of the transmission

system. FERC, the agency responsible for regulating

interstate energy commerce and the transmission grid,

is at the forefront of these changes. Its objective is to

make the power generation sector more competitive by

fostering wholesale power markets, and to make the

Nation’s transmission system more efficient. 

FERC Promotes

Wholesale Competition and

Transmission Efficiency

FERC has long believed that competition in electric

power generation could result in lower electricity prices

and improved services for wholesale and retail electricity customers. Beginning approximately in the mid1980s, FERC has issued numerous Orders, Policy Statements, or case rulings designed to promote competition

in wholesale power markets and to improve operation

of the transmission system. (Table 9 presents a chronological summary of these documents.) FERC’s objectives

center on five broad functions:

 Introducing market-based rates for wholesale

power sales

 Providing nondiscriminatory access to the power

transmission system

 Developing guidelines for recovery of stranded

costs 

 Promoting transparency of information about the

bulk transmission system

 Promoting development of regional transmission

organizations.
62 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Table 9. Overview of the Federal Energy Regulatory Commission’s Efforts Promoting Competition in

the Electric Power Industry

Date Description of FERC Efforts 

1985-1991

Prior to the Energy Policy Act, FERC encouraged and approved the use of market-based rates

representing one of FERC’s initial efforts to make the industry more efficient. Between 1985 and

mid-1991, FERC addressed 31 requests to sell wholesale electric power at market-based rates

(Notice of Public Conference and Request for Comments on Electricity Issues, Docket No. PL91-

1-000, April 1991).

July 1993

FERC issued a policy statement regarding Regional Transmission Groups (RTGs). The purpose

of RTGs was to facilitate the provision of transmission services to potential users of the

transmission system and to facilitate the resolution of disputes over provision of services. It was

believed by FERC that RTGs would encourage negotiated agreements between transmission

providers thereby avoiding the need for potentially time-consuming and expensive litigation before

FERC (Policy Statement Regarding Regional Transmission Groups, RM93-3-000, July 30, 1993).

May 1994

FERC established general guidelines for comparable transmission access for third parties.

Comparable access refers to the belief that owners of the transmission grid should offer third

parties access to the grid on the same or comparable basis and under the same or comparable

terms and conditions as the transmission owner’s use of the system. Comparable access is one

of the key ingredients of an open access transmission tariff specified in Order 888 (see below)

(67FERC61, 168).

October 1994

FERC issued its Transmission Pricing Policy Statement. Prior to this policy statement, FERC had

allowed only postage-stamp and contract path pricing of transmission services. In this policy

statement, FERC recognized the need to encourage a variety of other pricing methods that may

be more suitable for competitive wholesale power markets (Transmission Policy Statement, RM93-

19-001, October 1994, Final Rule Order on reconsideration and clarifying the policy statement,

May 22, 1995). 

April 1996

FERC issued Order 888, requiring all public utilities that own, control, or operate transmission

facilities to have on file an open access non-discriminatory transmission tariff. The Order also

permits public utilities to seek recovery of stranded costs associated with providing open access

(Order 888, Final Rule, RM95-8-000, and RM94-7-001, April 24, 1996). 

April 1996 FERC issued Order 889 establishing the Open Access Same-Time Information System.

December 1996

FERC issued a Policy Statement (Order 592) amending its procedures to evaluate potential

mergers between electric utilities. The procedures were designed to streamline the merger

application process, and update FERC’s evaluation of the merger to consider the merger’s effect

on competition, its effect on rates, and its effect on regulation.

January 1997 - December

1998

FERC conditionally approved five Independent System Operators (ISOs)&California ISO, ISONew England, New York ISO, Pennsylvania, New Jersey, Maryland (PJM) ISO (official name is

PJM Interconnection), and the Midwest ISO.

December 1999

FERC issued Order 2000 asking all transmission-owning utilities, including non-public utilities, to

place their transmission facilities under the control of an appropriate regional transmission

organization (RTO). So that utilities could comply with this request, the characteristics and

minimum functions of an appropriate RTO were defined in the Order (Order 2000, Final Rule,

RM99-2-000, December 20, 1999). 
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 63

85 D.F. Santa, “Analytical Flaws and Practical Pitfalls: Reconsidering FERC’s Merchant Affiliate Rules,” The Electricity Journal, Vol. 11,

No. 9 (November 1998).

Table 10. Companies Eligible to Sell Wholesale

Power at Market-Based Rates, as of

May 1, 2000

Type of Company

Number of

Companies

Independent Power Marketers . . 389

Affiliated Power Marketers . . . . . 117

Affiliated Power Producers . . . . . 154

Investor-Owned Utilities . . . . . . . 99

Other Utilities . . . . . . . . . . . . . . . 107

 Total . . . . . . . . . . . . . . . . . . . 866

 Source: Federal Energy Regulatory Commission, online

at www.ferc.fed.us/electric/PwrMkt/PM_LIST.htm (May

2000). 

Introducing Market-Based Rates for

Wholesale Power Sales 

In a regulated environment, wholesale and retail electricity power prices are calculated based on a utility’s

embedded costs plus a negotiated rate of return on their

investments. Because this method ensures that the utility

will cover its costs of operation, this method does not

have appropriate incentives to motivate a utility to fully

evaluate all the risks of an investment. If a utility invests

in what turns out to be an uneconomical project, it can

still add the costs of the investment to the price it

charges for electricity. Thus, the risks and economic

consequences of a poor investment are passed to the

electricity customer. Another limitation is that the costbased pricing concept is the antithesis of the objective of

promoting competitive wholesale power markets.

To overcome the limitations of cost-based pricing, in the

mid-1980s FERC considered 31 applications to use market-based pricing for wholesale transactions, although

only a few applications were approved. However, by the

mid-1990s, FERC had approved the use of market-based

rates for more than 100 power suppliers, and substantial

growth in their use had begun.

Currently, 866 companies are eligible to sell wholesale

power at market-based rates, including 389 independent

power producers, 271 affiliated power marketers and

producers, and 206 investor-owned utilities (IOUs) and

other utilities (Table 10). Affiliated companies must

comply with standards of conduct designed to eliminate

abuses and reciprocal dealing between the public utility

and its affiliated power marketer.85

The use of market-based prices started with bilateral

transactions, where buyers and sellers negotiated a

price. Since then, a few centralized power markets have

been created where a power supplier sells through a

power exchange, and wholesale electricity prices are

based on the market conditions at the exchange. Centralized power markets have begun in New England; New

York; Pennsylvania, New Jersey, Maryland (PJM) region;

and California. More are likely to open during the

coming years. Without blanket approval to sell power at

market-based rates, these competitive centralized

markets could not exist.

Providing Nondiscriminatory Access to the

Transmission System

Historically, many vertically integrated utilities did not

allow independent power suppliers to use their transmission systems. If they were ordered to provide access,

the integrated utilities would favor power from their

own plants over the independent supplier when the

transmission lines became congested. In some instances,

the utility would withhold certain types of important

transmission services. These practices stymied the

growth of competitive power generation markets

because they limited the extent to which independent

power suppliers could provide service to electricity

customers.

EPACT’s passage gave FERC broad authority to order

transmission-owning utilities to wheel power for wholesale power transactions, and it helped to relieve some of

the barriers to using the transmission system. Wheeling

occurs when a transmission-owning utility allows

another utility or independent power producer to move

(or wheel) power over its transmission lines. Although

FERC’s wheeling authority facilitated creation of competitive wholesale electricity markets, wheeling requests

were evaluated on a case-by-case basis, which was

sometimes slow and cumbersome. Also, disparities still

persisted in the comprehensiveness and quality of transmission services provided by transmission owners to

other users. To address disparities in service, in 1994

FERC established a “comparability standard” stating

that transmission-owning utilities should offer other

transmission users access to their transmission systems
64 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

on the same basis and under the same conditions as they

use the transmission systems to service their own

electricity customers. FERC also applied the comparability standard case-by-case; when a utility requested

approval for market-based rates or approval to merge

with another utility, FERC would specify that the utility

must incorporate the comparability standard into its

transmission tariff as a condition for approval.

Even with more wheeling authority and implementation

of the comparability standard on a case-by-case basis,

open non-discriminatory transmission access still did

not exist universally. In April 1996 FERC took action to

correct the lack of universal access by issuing Order 888.

At that time, Order 888 was considered the most farreaching and ambitious project undertaken by FERC to

eliminate deterrents to competition in the electric power

industry. Order 888 had two basic goals: (1) to eliminate

anti-competitive practices and undue discrimination in

transmission services through a universally applied

open access transmission tariff, and (2) to ensure the

recovery of stranded costs a utility might accrue in the

transition to competitive markets. 

With respect to the first goal, FERC imposed a blanket

requirement that all transmission-owning utilities under

its jurisdiction must file an open access transmission

tariff specifying the terms and conditions for using their

transmission systems. The comparability standard was

one of the required conditions of the transmission tariff.

One significant advantage of a universal transmission

tariff was that it eliminated FERC’s time-consuming

case-by-case evaluation of wheeling requests. Instead,

rights, terms, and conditions to wheel power were

predefined in the tariff and a company could respond

immediately to opportunities in short-term markets that

previously were not available to them in a timely

manner. Access to the transmission system in a timely

manner is essential for a competitive short-term power

market to function properly. 

Another equally important component of Order 888 was

the requirement for transmission owners to functionally

unbundle their activities. Functional unbundling

required the transmission owner to take transmission

service under the same tariff as other transmission users

(comparability standard); to separate rates for wholesale

generation, transmission, and ancillary services; and to

rely on the same electronic information network that its

transmission customers rely on to obtain information

about prices and available capacity of the transmission

system. Essentially, the idea of functional unbundling

was to avoid favoritism and discriminatory practices

within a vertically integrated utility by separating its

transmission services functions from other business

activities in the company. 

Order 888 covered other transmission tariff issues such

as pricing of transmission services, the application of

market-based rates for power sold from new capacity,

and other items. (Table 11 provides a summary of the

major provisions of Order 888 with respect to open

transmission access.) Since issuance of Order 888, all

utilities have filed their open access tariffs, and Order

888 is now history. In retrospect, Order 888 represented

FERC’s first broad sweeping effort to eliminate discriminatory and unfair practices in the management and

control of the transmission system.

Developing Guidelines for Recovery of

Stranded Costs

The second goal of Order 888 was to ensure that electric

utilities are able to recover their sunk costs in a competitive industry. These sunk costs are called stranded

costs, or transition costs, and they represent a utility’s

capital investments that are unrecoverable because of

the transition to competition. The rationale for allowing

stranded cost recovery is that utilities have invested

billions of dollars in facilities under a regulatory regime

that allowed cost recovery of all prudent investments.

To gain support and cooperation for a successful

transition to a competitive industry, and to be consistent

with the past decisions, FERC believed it was critical

that utilities recover these costs. At the same time, FERC

recognized that recovery of stranded costs may delay

some of the benefits of competitive power markets.

FERC’s Order 888 spelled out under what general

conditions a utility is entitled to recover its stranded

costs and from whom. As far as entitlements, Order 888

specified that cost recovery at the wholesale level is

limited to situations where there is a link between the

use of FERC’s required open access transmission tariff

and the loss of wholesale power customers. FERC went

further to specify that recovery of wholesale stranded

costs should be assigned to the departing customer. At

the retail level, FERC determined that States should

have primary jurisdiction over cost recovery resulting

from retail competition, although it would entertain

requests to recover costs resulting from retail competition when a State does not have the authority. 

FERC’s concerns for the recovery of wholesale stranded

costs may have been overestimated. Since Order 888 was

issued, FERC has on record seven stranded costs cases.

Moreover, as of April 2000, it had not received a filing

for wholesale stranded cost recovery in more than a year
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 65

Table 11. Major Provisions of FERC Order 888 on Open Access

Functional Unbundling

A utility's uses of its own transmission system for the purpose of

engaging in wholesale sales and purchases must be separated from

other activities. Corporate unbundling is not required.

3 Utilities must take transmission services (including ancillary

services) under the same tariff of general applicability as do

others.

3 Utilities must state separate rates for wholesale generation,

transmission, and ancillary services.

3 Utilities must rely upon the same electronic information network

that its transmission customers rely upon to obtain

transmission information.

Reciprocity

Transmission customers of jurisdictional utilities who take service

under the open access tariff and who own, control, or operate

transmission facilities must, in turn, provide open access service to the

transmitting utility. This includes municipally owned entities and RUS

cooperatives.

Services to be Provided

A public utility must offer transmission services that it is reasonably

capable of providing, not just those services that it currently provides

to itself and others.

Six ancillary services must be included in the open access tariff:

1. Scheduling, system control, and dispatch

2. Reactive supply and voltage control from generation sources 

3. Regulation and frequency response

4. Energy imbalance

5. Operating reserve&spinning reserve

6. Operating reserve&supplemental reserve.

The transmission customer must purchase the first two services from

the transmission provider.

Nondiscriminatory Open Access Tariff Requirement

By July 9, 1996, jurisdictional utilities that own or control transmission

must have filed a single open access tariff that offers both network,

load-based services and point-to-point, contract-based services,

including ancillary services, to eligible customers comparable to the

service they provide themselves at the wholesale level. The rule

provides a single pro forma tariff that sets forth minimum conditions for

both network and point-to-point services and nonprice terms and

conditions for providing those services and ancillary services.

Pools and Holding Companies

Jurisdictional utilities who are members of tight or loose power pools

must file either an individual pro forma tariff or a joint pool-wide pro

forma tariff by July 9, 1996. They are not required to take service for

pool transactions under that tariff, but are required to file a joint poolwide tariff no later than December 31, 1996, and begin to take service

under that tariff for all pool transactions by that same date. By that

date, they must also restructure their ongoing operations and open

membership to nonutilities.

Public utility holding companies not subject to tight or loose pool

requirements are required to file a single system-wide pro forma tariff

permitting transmission service across the entire holding company by

July 9, 1996.

All bilateral economy energy coordination contracts executed before

the effective date of this rule must be modified to require unbundling of

any economy energy transaction occurring after December 31, 1996.

Pricing

The rule does not prescribe rates for network, point-to-point, or

ancillary services. Instead, utilities may charge current rates or apply

for new transmission rates. Utilities can propose to recover opportunity

costs and expansion costs. Crediting for customers' transmission

facilities will be permitted on a case-by-case basis. Proposed pricing

must conform with FERC's Transmission Pricing Policy Statement.

Contract Reform

The rule does not void any existing requirements contracts. The

functional unbundling requirement applies only to transmission

services under new requirements contracts, new coordination

contracts, and new transactions under existing coordination contracts.

Parties to requirements contracts executed on or before July 11, 1994,

may seek modification of such contracts on a case-by-case basis,

even if they contain a Mobile-Sierra clause. FERC, however, does not

take contract modification lightly and parties seeking to modify

contracts will have a heavy burden to demonstrate the need for it.

Customer Eligibility

Any entity engaged in wholesale purchases or sales of energy or retail

purchases is an eligible customer.

Market-Based Rates

Utilities seeking market-based rates for sale of electricity at wholesale

from new capacity are no longer required to demonstrate lack of

market power in generation. New capacity is that for which

construction has commenced on or after the effective date of this rule.

For existing generation, FERC will continue its case-by-case approach

that includes an analysis of generation market power in first- and

second-tier markets.

 Source: Adapted from “FERC Finalizes Electric Industry Restructuring Rule,” Public Utility Topics (Philadelphia, PA: Coopers & Lybrand,

L.L.P., June/July 1996), No. 96-2, p. 4.
66 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

86 Personal conversation with the Federal Energy Regulatory Commission, April 3, 2000. 87 Federal Energy Regulatory Commission, “Open Access Same-Time Information System and Standards of Conduct%Order 638,”

(February 25, 2000). 88 Regional Transmission Organizations (RTOs) have also been called power pools, regional transmission groups (RTGs), and

independent system operators (ISOs). They are all similar in that they represent a grouping of transmission facilities owned by different

electric utilities to achieve common objectives. Their missions, scope of responsibilities, and objectives, however, were different. 

and a half.86 The overwhelming majority of stranded

costs awards have been in States that have implemented

retail competition. Chapter 8 contains a discussion of

stranded costs resulting from States introducing retail

competition.

Promoting Transparency of Information

About the Bulk Power Transmission System

To follow through with non-discriminatory access to the

transmission system, timely and accurate day-to-day

information about transmission must be unrestricted

and public to all transmission users. To implement this

concept, in 1996 FERC issued Order 889 requiring all

IOUs to participate in the Open Access Same-Time

Information System (OASIS). 

The OASIS is an interactive Internet-based database

containing information on available transmission capacity, capacity reservations, ancillary services, and transmission prices. The underlying idea of the OASIS is to

create an interactive computerized market for transmission-related products and services which is accessible by all qualified users of the transmission system. In

that role, the OASIS facilitates the functioning of

competitive power markets. 

The OASIS became operational in January 1997. Currently, 23 OASIS nodes are on the Internet, and

approximately 166 transmission owners participate by

providing information about their transmission facilities.

Initially the OASIS had operational problems traceable

to a lack of common data elements and business practices. This condition made it difficult to compare data

between nodes, and to conduct business over multiple

nodes. Recently, OASIS developers have adopted a common set of Business Practice Standards to improve the

interaction between transmissions providers and

customers over the OASIS.87 Implementation of these

standards should move the OASIS further along in

becoming a useful tool in support of a competitive

industry.

Promoting Development of Regional

Transmission Organizations

Promoting regional transmission organizations (RTOs)

is the last of FERC’s major objectives discussed in this

chapter. It arguably can be called FERC’s most significant and, to some extent, most tumultuous activity

undertaken in its effort to create a more competitive and

efficient industry.

The concept of regional organizations in the electric

power industry has existed for some time. Many

regional entities have been created for planning, coordination, or system reliability functions. The most visible

are the 10 Regional Reliability Councils that develop

standards and procedures to maintain the reliability of

the Nation’s power system. Some industry observers

have noted that perhaps there are too many regional

entities, and that regional decision-making authority and

responsibility sometimes becomes blurred. 

RTOs refer to the idea of organizing the operation,

control, and possible ownership of the transmission grid

into independent companies or organizations; the process of forming RTOs is also referred to as grid

regionalization.88 Regional control of the transmission

grid has many coordination and efficiency advantages

over the current balkanized configuration where each

vertically integrated utility operates and controls its own

transmission facilities.

FERC’s effort to foster grid regionalization consists of

three progressively ambitious initiatives. In 1993 FERC

issued a policy statement recommending that transmission owners, transmission customers, and other

interested parties form regional transmission groups

(RTGs) to coordinate transmission planning and expansion on a regional and inter-regional basis (Table 9). A

few RTGs were established, but their role has been

limited. Although effective for planning purposes, these

organizations were usually not vested with appropriate

decision-making authority needed to address transmission issues affecting an entire region. 

In its next initiative, FERC used a stronger and more

ambitious approach to grid regionalization. In Order

888, FERC encouraged the formation of independent

system operators (ISOs), whereby utilities would

transfer operating control of their transmission facilities

to the ISO. Ownership of the facilities would remain

with the utility. Utility participation in an ISO was

voluntary.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 67

89 The intent of FERC’s functional unbundling requirement, specified in Order 888 and discussed above, was to accomplish the same

thing without the need for separate organizations. 90 Federal Energy Regulatory Commission, “Notice of Proposed Rulemaking , Regional Transmission Organization,” RM99-2-000 (May

13, 1999). 91 North American Electric Reliability Council, “Reliability Assessment 1998-2007” (September 1998). 92 Secretary of Energy Advisory Board's (SEAB) Task Force on Electric System Reliability, “Maintaining Reliability in a Competitive U.S.

Electric Industry” (September 29, 1998).

By encouraging ISO formation, FERC underscored its

belief in the importance of unbundling power generation

and marketing from operation and control of the transmission grid. An ISO with no economic interest in

marketing and selling power could administer fairly the

open access transmission tariff and eliminate discriminatory practices, and at the same time achieve the

efficiency benefits from regional control of the grid.89

Since Order 888 was issued, six ISOs have been formed

and five of them are now operating. (The status of these

ISOs is discussed later.)

Remaining Impediments to Competitive

Power Markets After Order 888

Even with five ISOs operating and open access transmission tariffs in place, the development of wholesale

power markets across the nation has been slow, and

obstacles to competition still remain. Three major

obstacles have been mentioned. First, since Order 888

was issued the Commission has received many complaints of transmission owners discriminating against

independent power companies. Further, the Commission noted that an increase in the number of market

participants and transactions in wholesale markets has

made discriminatory behavior with regard to transmission access more subtle and more difficult to

identify.90 Second, the Commission observed that electric

utilities’ implementation of functional unbundling has

not produced sufficient separation between operating

the transmission system and marketing and selling

power, and that this lack of separation contributes to

discriminatory behavior. Third, grid regionalization

through ISOs has occurred in some areas of the country,

but was not implemented in other areas. Although

creation of an ISO was voluntary, expectations were that

more regions would seek to realize the benefits of grid

regionalization and would participate in forming ISOs.

In addition to these obstacles, an increase in market

participants and trading over the past few years, and

changes to electricity trading patterns has made system

reliability more difficult to maintain which impedes

creating fully competitive power markets. The North

American Electric Reliability Council (NERC) reported

that, “[in recent years] the adequacy of the bulk power

transmission system has been challenged to support the

movement of power in unprecedented amounts and in

unexpected directions.”91 This view is supported by a

U.S. Department of Energy Task Force noting that “there

is a critical need to be sure that reliability is not taken for

granted as the industry restructures, and thus does not

fall through the cracks.”92

Not only has maintaining reliability become more

difficult, other obstacles to competitive markets have

emerged. Transmission congestion has increased, but

current procedures for relieving congestion are antiquated and sometimes unfair. As FERC points out, “current transmission loading relief (TLR) procedures [for

relieving congestion] are cumbersome, inefficient, and

disruptive to power markets because they rely

exclusively on physical measures of [electricity] flows

with no attempt to assess the relative costs and benefits

of alternative congestion management techniques.”

Another problem is that planning for transmission

expansion is more difficult than in the past because of

more uncertainty in the industry. Responsibilities for

transmission expansion are not always clear, the motivation for construction of new facilities is changing, and

cost recovery after construction may be more risky than

in the past. Finally, the current method of transmission

pricing is antiquated given the new competitive environment. In most of the United States, the transmission

customer pays separate additive access charges every

time the power crosses the boundary of a transmission

owner. This practice is referred to as pancaked pricing,

which has the effect of raising the cost of transmission

and reducing the geographic size of competitive power

markets.

Order 2000 and Grid Regionalization

FERC’s third initiative to grid regionalization, which is

currently being implemented, is perhaps its most

ambitious effort. In December 1999, FERC issued Order

2000, calling for the voluntary creation of RTOs

throughout the United States. FERC had noted that all of

the Nation’s transmission systems should be brought

under regional control and perhaps regional ownership

in order to eliminate the remaining discriminatory

practices, meet the increasing demands placed on the
68 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

transmission system, and achieve fully competitive

wholesale power markets. If FERC’s implementation of

Order 2000 is successful, the transmission system will

go from a system owned and controlled mostly by

vertically integrated electric utilities to a system owned

and/or controlled by a few, but uncertain number of,

unaffiliated RTOs.

With this formidable undertaking, the Commission

again believes a voluntary approach will be successful

because (1) many vertically integrated utilities recognize

the benefits of an RTO, (2) Order 2000 provides clear

rules and guidance for utilities to follow in forming an

RTO, (3) to facilitate cooperation, the Commission

established a collaborative process for RTO development, and (4) Order 2000 provides ratemaking incentives for companies who assume the risks of a transition

to a new corporate structure. (Table 12 contains a

summary of the major components of Order 2000.)

Potential Benefits of Regional Transmission

Organizations Through Order 2000

By eliminating the balkanized control of the transmission grid, regionalization has the potential to increase

significantly the overall operating efficiency of the

industry system. Many industry analysts believe that

combining the control of individual transmission

systems under one regional organization with a wide

regional scope can lead to improvements in transmission

pricing, improved management of congestion, improved

information relevant to promoting competition in power

markets, better management of parallel path flow

problems, improved reliability management, and as

noted above, the elimination of remaining discriminatory practices concerning access to the transmission

system services. The term potential is a key word

because regionalized control of the Nation’s transmission grid, as proposed in Order 2000, is a new and

unproven concept. These potential benefits, some of

which were alluded to in the above discussion, are

covered below in more detail.

Eliminate remaining opportunities for discriminatory

transmission practices: As organizations completely

independent from power production and sales, RTOs

will sever the economic incentives between power marketing and control of the transmission system. Without

the economic incentive, the reasons for discriminatory

practices should be eliminated. Functional unbundling

required in Order 888 did not eliminate economic

incentives, and was not completely effective in eliminating discriminatory practices.

Improve calculations of available transmission capacity: Available transmission capacity (ATC) is a measure

of the amount of transmission capacity that is available

to transmit power over the grid at a particular time.

Market participants use this information to make shortterm decisions to purchase or sell power. ATC is

difficult to calculate due to constantly changing conditions and the complexity of the electrical network. The

difficulty is compounded in a balkanized network where

each utility calculates its own ATC. An RTO with

regional scope will have better information on conditions of the network than an individual utility; with

better information, more accurate estimates of ATC will

be available to transmission users. Also, FERC has

pointed out that many complaints have been filed

claiming that transmission providers are calculating

ATC to favor their own generators, which is a form of

discrimination. An independent RTO will eliminate this

behavior.

Improve management of parallel path flow and system

reliability: The interconnection of the transmission grid

makes management a difficult and challenging task. One

of the biggest problems is managing parallel path flow

(also called loop flow). Parallel path flow refers to the

fact that electricity flows across an electrical path

between source and destination according to the laws of

physics, meaning that some power may flow over the

lines of adjoining transmission systems inadvertently

affecting the ability of the other region to move power.

This cross-over can create compensation disputes among

the affected transmission owners. It also impacts system

reliability if a parallel path flow overloads a transmission line and decisions must be made to reduce (curtail)

output from a particular generator or in a particular

area. An RTO with access to regionwide information on

transmission network conditions, with regionwide

power scheduling authority, and with more efficient

pricing of congestion can better manage parallel path

flows and reduce the incidence of power curtailment. 

Improve transmission pricing methods: Pricing of

transmission services is one of the most important issues

in restructuring the Nation’s transmission system. Historically, FERC has based its approach to transmission

prices on the rolled-in average historic costs of the

transmitting utility. This method was largely developed

for requirements service where the wholesale customer’s

load was dispersed throughout the utility’s service

territory and integrated generation and transmission

facilities are used. The result has been a “postage stamp”

rate. Postage stamp rates have important limitations,

particularly in providing price signals to transmission
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 69

Table 12. Summary of Major Provisions of the Federal Energy Regulatory Commission’s Order 2000 

Final Rule Establishing Regional Transmission Organizations

Filing Requirements and Deadlines

1. Each public utility that owns, operates, or controls interstate transmission facilities (except those already participating in an

approved regional transmission entity) must file by October 15, 2000, a proposal to participate in a regional transmission

organization (RTO) that will be operational by December 15, 2001, or they must file, by the same date, a description of efforts

to participate in an RTO, obstacles to participation, and plans and a timetable for future efforts.

2. Each public utility that is a member of an existing transmission entity that conforms with the 11 ISO principles contained in

Order 888 must file by January 15, 2001, a description that explains the extent to which the transmission entity in which it

participates meets the minimum characteristics and functions of an RTO, and how it proposes to modify the entity to become

an RTO, or a description of efforts, obstacles, and plans to conform to an RTO’s minimum characteristics and functions.

3. All RTOs will implement their minimum functions according to the following schedule:

 Congestion management function by December 15, 2002

 Parallel path flow coordination function by December 15, 2004

 Transmission planning and expansion function by December 15, 2004

 Other minimum functions will be implemented by startup.

Minimum Characteristics of a Regional Transmission Organization

1. Independence: The RTO must be independent of market participants. Independence can be achieved by meeting three

conditions: (1) the RTO, its employees, and any non-stakeholder director must not have any financial interest in any market

participants, (2) the RTO must have a decision-making process independent of control by any market participant, and (3) the

RTO must have exclusive authority under Section 205 of the Federal Power Act to file changes to its transmission tariff. 

2. Scope and Regional Configuration: The RTO’s region must be of sufficient scope and configuration to perform effectively

its required function and to support efficient and nondiscriminatory power markets. FERC will evaluate the configuration or

boundaries of the RTO according to the extent it meets nine criteria:

 Facilitates performing essential RTO functions

 Encompasses one contiguous geographic area

 Encompasses a highly interconnected portion of the grid

 Deters the exercise of market power

 Recognizes existing trading patterns

 Takes into account existing regional boundaries (e.g., NERC regions)

 Encompasses existing regional transmission entities

 Encompasses existing control areas

 Takes into account international boundaries.

3. Operational Authority: The RTO must have operational authority for all transmission facilities under its control, and it also

must be the security coordinator for the region. The security coordinator ensures the real-time operating reliability of the power

systems.

 

4. Short-Term Reliability: The RTO must have exclusive authority for maintaining the short-term reliability of the transmission

grid under its control. Short-term is intended to include all time periods necessary for the RTO to satisfy its reliability

responsibilities up to the planning horizon.

Minimum Functions of a Regional Transmission Organization 

1. Tariff Administration and Design: The RTO will be the sole administrator of its own tariff and, therefore, it will be the sole

decision-making authority on provision of transmission service including the decision to establish new interconnections.

2. Congestion Management: The RTO will ensure the development of market mechanisms to manage transmission congestion.

These mechanisms should provide price signals to transmission customers regarding the consequences of their transmission

usage decisions.
70 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Table 12. Summary of Major Provisions of the Federal Energy Regulatory Commission’s Order 2000

Final Rule Establishing Regional Transmission Organizations (Continued)

3. Parallel Path Flow: The RTO must implement procedures within 3 years of start-up to address the problems associated with

interregional parallel path flow and implement procedures immediately for regional parallel path flow. Parallel path flow refers

to the fact that electricity flows over transmission lines according to the laws of physics. Because of these laws, the power

generated in one region may flow over the transmission lines of another region, inadvertently affecting the ability of the other

region to move power. 

4. Ancillary Services: The RTO must serve as the provider of last resort for all ancillary services as required in Order 888. The

RTO should promote creation of competitive markets for procurement of these services. 

5. Open Access Same-Time Information System (OASIS) and Capability Calculations: The RTO should act as a single

OASIS node. The data elements of total transmission capability and available transmission capability, which are stored on the

OASIS and used by potential transmission customers, will be calculated by the RTO, or if provided by the transmission owner,

verified by the RTO.

6. Market Monitoring: The RTO will submit to FERC a market monitoring plan that (1) ensures that there is objective information

about the markets, (2) contains procedures for proposing efficiency improvements, market flaws, and market power, and (3)

contains procedures to evaluate the behavior of market participants. 

7. Planning and Expansion: The RTO must develop a planning and expansion proposal that (1) encourages market-motivated

operating and investment actions for preventing and relieving congestion, (2) accommodates efforts by State regulatory

commissions to create multi-state agreements to review and approve new transmission facilities and coordinates with existing

regional transmission groups, and (3) files a plan with milestones showing that the RTO will meet its planning and expansion

requirements no later than 3 years after start-up.

8. Interregional Coordination: The RTO will develop mechanisms to ensure the integration of reliability practices within an

interconnection and market interface practices among regions.

Open Architecture

Open architecture refers to the idea that RTOs should be designed so that improvements in their structure, operating rules,

and other activities can evolve over time.

Policy for an RTO’s Transmission Rates

 

FERC believes that effective transmission rates are essential in promoting economic efficiency in the generation and transmission

sectors, and are an important factor to the success of the RTO as a stand-alone transmission business. FERC has approval

responsibility for an RTO’s transmission rate schedule. According to FERC policy, effective transmission rates will address the

following issues:

1. Eliminate Pancake Pricing: Pancake pricing occurs when a transmission customer is charged separate access charges for

each utility service territory crossed by the transmission customer’s power transaction. Pancaking increases the price of

electricity and it discourages competition in the generation sector. By combining transmission systems under one RTO, a wider

area served by a single rate can be designed.

2. Reciprocal Waiving of Access Charges Between RTOs: FERC encourages the RTOs to waive transmission access

charges for transactions that cross RTO borders. This increases the size of the competitive trading area beyond the RTO

border. 

3. Uniform Access Charges: FERC encouraged that an RTO establish one uniform access charge for all transmission

customers. However, they recognized that this approach may result in cost shifting (i.e., low-cost transmission providers would

see a rate increase, and high cost providers a rate decrease). As a temporary solution, FERC will allow a single rate, but that

rate will vary based on where the customer is located. 

4. Congestion Pricing: Congestion pricing is closely related to congestion management in that effective pricing of congestion

problems provides the appropriate price signals to build additional transmission lines or power generation plants in order to

eliminate congestion.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 71

Table 12. Summary of Major Provisions of the Federal Energy Regulatory Commission’s Order 2000 

Final Rule Establishing Regional Transmission Organizations (Continued)

5. Service to Transmission-Owning Utilities that do not Participate in an RTO: FERC intends to permit an RTO to propose

rates, terms, and conditions of transmission service that recognize the participatory status of transmission customers. In other

words, a transmission customer who is also a transmission provider in the region that chose not to join the RTO, will have a

different transmission tariff than other customers. 

6. Performance-Based Regulation: Performance-based regulation (PBR) represents the concept of offering financial incentives

to lower rates or costs. Under PBR, good performance can be rewarded with higher profits and poor performance can be

penalized in some manner. As an alternative to cost-based regulation, FERC encourages the RTO to develop PBR proposals,

although submission of a proposal is voluntary. 

7. Other RTO Transmission Rate Reforms: To encourage investment in transmission facilities and efficiency in operation,

FERC indicated that it would consider other innovative transmission pricing proposals such as a higher return on equity than

previously allowed, levelized rates, or accelerated depreciation and incremental pricing for new transmission investments. 

8. Additional Ratemaking Issues: This section of Order 2000 contained a wide range of comments on ratemaking issues not

specifically addressed in the notice of proposed rulemakiing. These comments cover issues ranging from alternative ratemaking

methods to issues dealing with how to incorporate incentives to promote environmentally benign resources. 

9. Filing Procedures for Innovative Rate Proposals: FERC will evaluate innovative rate proposals based on how the proposed

rate treatment would help achieve the goals of an RTO. Rate moratoria or returns on equity that do not vary according to the

RTO capital structure may not be included in the RTO’s rate structure after January 1, 2005.

Other Issues

In Order 2000, FERC identified nine issues, other than the ones discussed above, which may have an impact on the structure,

completeness, regulation, and design of RTOs. 

1. Public Power and Cooperative Participation in RTOs: FERC expects public power entities to participate in the formation

of RTOs, but it is aware public power entities face several obstacles. The Internal Revenue Service Codes may prevent facilities

financed by tax-exempt debt from wheeling privately owned power, or they may prevent transfer of operational control of

transmission facilities financed by tax-exempt debt to a for-profit transmission company. State and local government laws may

prevent public power entities from participating in RTOs. The lack of participation of public power entities may negate some of

the effectiveness and expected benefits of RTOs.

2. Participation by Canadian and Mexican Entities: FERC opined that Mexican and Canadian participation in an RTO would

be beneficial.

3. Existing Transmission Contracts: FERC indicated that it will examine, case-by-case, how to handle existing contractual

arrangements when forming an RTO. For example, one issue may involve how to handle pancaked rates in existing contracts

for others when transmission-owning utilities design a non-pancaked rate for their own transactions. 

4. Power Exchanges: FERC will leave it to each region to determine a need for a power exchange, and if the RTO should

operate the exchange should there be a need. 

5. Effects on Retail Markets and Retail Access: FERC opined that formation of an RTO will not affect the ability of States to

implement retail markets and competition. In Order 2000, FERC noted that experience with the independent system operators

(ISOs) indicates that an RTO could be a benefit to States that are implementing retail competition.

6. Effects on States with Low-Cost Generation: Some States are concerned that an RTO would result in local utilities selling

their low-cost power to other States. FERC asserted that an RTO will provide access to future low-cost generation plants and

that new low-cost generation plants will be attracted to regions with an RTO because of dependable and nondiscriminatory

access to the transmission system. 

7. States’ Role With Regard to RTOs: FERC believes that States have an important role to play, but they chose not to specify

what role in Order 2000.
72 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Table 12. Summary of Major Provisions of the Federal Energy Regulatory Commission’s Order 2000

Final Rule Establishing Regional Transmission Organizations (Continued)

8. Accounting Issues: FERC will require that RTOs conform to the Uniform System of Accounts, but they also indicated that

changes in the industry require them to re-examine existing accounting and related reporting requirements. 

9. Market Design Lessons: FERC envisions that bid-based markets for wholesale electric power will be a central feature in

many RTO proposals. Although bid-based markets for electric power do not now represent the dominant method for buying and

selling electricity, this method is expected to grow. In Order 2000, FERC summarizes lessons learned from its analysis and

approval of bid-based markets for four independent system operators. As these and other power markets mature, additional

information on how to design and operate power markets will develop.

 Multiple Product Markets: Efficiency of a multi-product market operating in the same time period is maximized when

arbitrage opportunities reflected in the bids are exhausted. That is, it is efficient when, after the RTO’s market has cleared,

no market participant would have preferred to be in another of the RTO’s markets. 

 Physical Feasibility: Transaction in the market should be physically feasible.

 Access to Real-Time Balancing Market: Real-time balancing refers to the moment-to-moment matching of loads and

generation on a system-wide basis. A real-time balancing market should be available to all grid users for purposes of

settling their individual imbalances.

 Market Participation: Markets are more efficient with a broad participation.

 Demand-Side Bidding: The current wholesale power markets do not offer customer demand-side bidding, only power

suppliers bid into the markets. However, demand-side bidding, to the extent it is practical, is desirable to make electricity

supply and prices more responsive to competitive markets.

 Bidding Rules: The market should allow generators to make bids that approximate their costs.

 Transaction Costs and Risks: Transaction costs should be low and participation in the market should involve no

unnecessary risk.

 Price Recalculations: Market clearing prices should minimize electricity price recalculations.

 Multi-Settlement Markets: Multi-settlement markets may involve a day-ahead market and a real-time market. If the dayahead market bids are needed for reliability, these bids need to be physically binding and may be subject to penalties for

failing to adhere to the bid.

 Preventing Abusive Market Power: FERC highlights three items which will help to lessen the potential for market power:

(1) have fewer restrictions on importing power into the region, (2) have less segmentation of geographic markets for the

same product, and (3) stop allowing market participants to change bids before they complete the financial settlement. Bid

changing can be used as signaling to facilitate collusive behavior.

 Market Information and Marketing Monitoring: Market clearing prices and quantities should be transparent so that

market participants can assess the market and plan their business efficiently.

 Prices and Cost Averaging: Transmission and congestion prices based on average costs may distort power production,

power consumption, and investment decisions. More innovative pricing methods are needed.

Collaborative Process: FERC asserted its commitment to hold regional workshops to assist in the voluntary formation of RTOs.

Five workshops were held in March and April 2000.

 Sources: Federal Energy Regulatory Commission, “Regional Transmission Organizations, Order No. 2000,” 18 CFR Part 35

(December 20, 1999); L.S. Hyman, What’s Inside FERC’s Transmission Policy: A Guide To Order 2000 (Vienna, VA: Public

Utilities Reports, January 2000).

users. Such rates may not reflect the cost of scarcity

when there is a bottleneck on the grid, the costs of

expanding capacity to remove such a bottleneck, or the

costs of transmitting power over long distances.

In addition to the potential inefficiencies, each transmission owner had its own rate structure which worked

when the industry was totally regulated and wholesale

electricity markets were relatively small or nonexistent

and electricity trading was infrequent. Competitive

wholesale power markets require more efficient and

equitable pricing methods that eliminate the possibility

of pancaked pricing which can double or triple the price

of the transaction, making it more difficult for electricity

suppliers that have to cross multi-transmission boundaries to be cost competitive. Under Order 2000, RTOs

will be required to design pricing methods that eliminate

pancaked prices. Also, Order 2000 encourages RTO

applicants to consider innovative transmission pricing

methods such as performance-based ratemaking (PBR),

or levelized rates, to replace the inefficient transmission

pricing methods currently used.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 73

93 A definition of “market participant” was problematic, and FERC, after considering extensive comments, concluded that market

participants is an entity whose economic or commercial interest is likely to be affected by an RTO’s decision and actions. The Regulatory

Text, Part 35, Chapter I, Title 18 CFR, 35.34(b2) contains a full definition of “market participant.”

Improve management of transmission congestion:

Transmission congestion occurs when a transmission

line reaches its transmitting capacity and additional

power from a specific generator cannot be dispatched as

needed. Congestion is caused by generation or power

grid outages, increases in energy demand, loop flow

problems, or a combination of these factors. 

In the past, transmission owners had responsibility for

the management of congestion on their transmission

systems. Usually, adequate transmission facilities

existed to support the flow of electricity within each

transmission owner’s system; however, when congestion

occurred, the common approach was to curtail power to

relieve the congestion. In a competitive environment,

administrative curtailment is no longer an acceptable

technique for congestion management. By not evaluating

the costs of congestion, administrative curtailment

provides no price signals or economic incentives to

reduce congestion, and in that respect it is incompatible

with competitive markets. In Order 2000, the Commission requires that an RTO develop mechanisms that

measure congestion costs and that market participants

are made aware of the cost consequences of their

transmission usage decision. FERC leaves it up to the

RTO to design a congestion pricing method to suit its

needs. 

Improve reliability of the transmission grid: Because an

RTO typically covers a larger region, it enhances coordination among key players during system emergencies.

Additionally, it can better coordinate or schedule

generation and transmission outages and the sharing of

ancillary services. An independent RTO can conduct

more objective reliability studies of the system than

others who may have vested interests in certain

outcomes.

Major Issues in Forming a Regional

Transmission Organization

Creating RTOs nationwide is a formidable task, and

many difficult issues must be addressed. In addition to

the problems unique to each region of the country, there

are also generic problems applicable to all regions. Three

important generic issues are the RTO’s size, organizational structure, and transmission grid coverage.

Determining the appropriate size of an RTO: The

Commission did not prescribe boundaries for an RTO,

but notes that a region sized appropriately will be

sufficient to permit the RTO to effectively perform its

required functions and to support efficient and

nondiscriminatory power markets. The Commission

specified regional configuration factors to evaluate the

appropriateness of the proposed RTO’s configuration.

The region configuration should be large enough so that

the RTO can make accurate and reliable ATC calculations, resolve loop flow issues internally within the

region, manage congestion effectively, offer nonpancaked transmission rates, effectively operate one

OASIS site, and conduct transmission planning and

expansion effectively. The specific boundaries of an RTO

will be evaluated using nine criteria (Table 12, Minimum

Characteristic 2).

A reading of Order 2000 requirements with respect to

the appropriate size of an RTO makes clear a few points.

FERC does not have any apparent preconceived notion

of the appropriate size of an RTO, only that determining

the right size will involve evaluating many factors. One

size does not fit all regions, so different configurations

are likely. To maximize the benefits of an RTO, it

appears that the larger the region covered by the RTO

the better, to a point. Technical factors, as well as

managerial, economic, and political factors need to be

evaluated to determine an optimal size. 

Determining the appropriate ownership structure of an

RTO: One of the most important factors in determining

the appropriate ownership structure for an RTO is its

ability to achieve independence from market participants.93 FERC commented in Order 888 that “the

principle of independence is the bedrock upon which the

ISO must be built and that this principle must apply to

all RTOs, whether they are ISOs, transmission companies (Transcos), or variants of these two models.

Order 2000 enumerates three conditions for independence: (1) the RTO’s employees and any nonstakeholder

directors must not have any financial interest in any

market participants; (2) the RTO must have a decisionmaking process that is independent of control by any

market participant or class of participants; and (3) the

RTO must have exclusive and independent authority to

file changes to its transmission tariff with the

Commission under section 205 of the Federal Power Act.

The effect of ownership on an RTO’s independence

depends on which ownership model is used. The two

basic models are the ISO model and transmission
74 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

company (Transco) model. With the ISOs that are currently operating, ownership of the transmission facilities

remained with the vertically integrated electric utility,

but operating control of the facilities was transferred to

the ISO. These ISOs operate as nonprofit and nonshare

companies and their independence from market

participants is established through representation and

voting privileges of its governing board.

The Transco is an independent, self-sustaining, profitmaking transmission company. Under this model, the

Transco owns the transmission facilities and the issue of

independence concerns ownership of the company itself.

The Commission noted that it will permit market

participants to retain limited active ownership (up to 5

percent for a single market participant and 15 percent

for a class of market participants) in the RTO during a 5-

year transition period. Active ownership refers to

ownership of voting securities that gives the owner the

ability to influence or control an RTO’s operating and

investment decisions. An active ownership interest will

terminate after 5 years.

In Order 2000, FERC has noted its openness to consider

any type of ownership and governance structure as long

as the RTO’s design meets the minimum characteristics

requirement of Order 2000. FERC has stated that “it is

important that we provide current transmission owners

with flexibility in deciding how they will relinquish

ownership or control of their transmission facilities to an

RTO.” Flexibility in ownership allows for regional

differences.

Avoiding gaps in regional coverage of the transmission

grid: For an RTO to realize its full potential, its must

have control and authority over the entire transmission

grid in the region. Gaps or breaks in continuity of

coverage of the grid undermine the RTO’s effectiveness

and the achievement of the benefits it can provide.

Because joining an RTO is voluntary, some utilities may

decide not to participate. IOUs choosing not to participate are required to file reasons and obstacles for not

participating. This procedure should invoke a dialogue

with FERC and provide a mechanism to overcome

obstacles to participation. Because IOUs are jurisdictional utilities, FERC also has some leverage in

convincing IOUs to participate. 

On the other hand, federally owned and other public

power and cooperative utilities are non-jurisdictional

utilities; they have no filing requirements under Order

2000 and FERC has no apparent leverage in obtaining

their participation. Because these utilities own approximately 30 percent of the Nation’s power grid, the

potential exists for substantial gaps in regional coverage.

For example, in the northwest and southeast regions of

the United States, federally owned utilities are major

providers of electricity with substantial ownership in

transmission facilities. RTO formation in those regions

may be impractical without their participation.

In Order 2000, FERC encourages non-jurisdictional

utility participation, but also recognizes that municipally

owned utilities face numerous regulatory and legal

obstacles. The Internal Revenue Code has private use

restrictions on the transmission facilities of municipally

owned utilities financed by tax-exempt bonds. State and

local government limitations, such as prohibitions on

participating in stock-owning entities and other

restrictions, may also impede full participation. FERC,

through the collaborative process, seeks solutions to

these problems, but the outcome is uncertain.

Status of Regional Transmission

Organizations

Although FERC has encouraged formation of independent RTOs, development of them has been sporadic;

most of the Nation’s transmission grid is not under

control of an independent RTO. Five ISOs have formed

over the past 2 years and are now operating&California

ISO; Pennsylvania, New Jersey, Maryland (PJM) ISO;

ISO New England; New York ISO; and ERCOT ISO

(Figure 27). The Midwest ISO has received regulatory

approval and much of its operating infrastructure has

been assembled; it should take operating control of the

transmission grid in the near future.

Several factors have contributed to the current set of

approved ISOs. PJM, New England, and New York ISOs

were created from existing tight power pools. A tight

power pool functions as one control area. Unlike ISOs,

power pools did not have control of transmission

facilities, they were not independent from transmission

owners, and they did not administer a regional open

access transmission tariff. According to Order 2000, “it

appears that the principal motivation for these tight

power pools forming ISOs was to establish a single

system-wide transmission tariff as required by Order

888.” In contrast, State legislation that opened California’s electric industry to retail competition required

the formation of the California ISO. The Public Utility

Commission of Texas created the ERCOT ISO.

Originally, the Midwest ISO consisted of voluntary

members. Subsequent to its initial formation, electric
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 75

ERCOT

ISO

Alliance

TRANSCO

New York

ISO

N E

ISO

PJM

ISO M idwest

ISO

In operation (ISOs have been approved by the Federal Energy Regulatory Comm ission and 

the State public utility comm ission). 

In planning or under discussion.

Midwest ISO has received FERC’s conditional approval and has m uch of its infrastructure in 

place. A ctual operating date has not been announced.

C A

ISO

MAPP

Regional 

Transmission 

Group

SPP

RTO

North 

West

RTO

Figure 27. Independent System Operators and Regional Transmission Organizations in Operation or

Under Discussion as of April 1, 2000

utilities in Illinois and Wisconsin have joined the

Midwest ISO because of State legislation requiring either

utility participation in an ISO or divestiture of their

transmission assets. 

A comparison of the six ISOs show many similarities,

although many of the implementation details are

different (Table 13). All of the ISOs are nonprofit

organizations. Four of the ISOs operate as a single

control area; ERCOT and the Midwest ISO have multiple

control areas within their regions. 

With the exception of the ERCOT ISO, all other ISOs

have developed a single access charge to the ISO-controlled transmission systems, based on the costs of the

transmission owner serving the customer. Access

charges are used to recover the transmission owner’s

embedded transmission system costs, and are calculated

based on dollar per megawatthour of transmission

system usage. Under this system, the transmission

customer pays only one access charge regardless of the

number of individual transmission systems crossed in

the ISO-controlled grid, so pancaked charges have been

eliminated. Most of the ISOs are moving toward

development of one uniform access charge for the entire

ISO-controlled grid. 

Three of the ISOs (California, PJM, and New York) use

bid prices to manage transmission congestion in their

region. In general, the power generators submit

voluntary bids to reduce output and relieve congestion,

and the ISO uses the bids to calculate the costs (or price)

of transmission congestion. The costs are assigned to the

appropriate transmission user. This technique places a

value on congestion and it provides a basis for economic

decision-making. Managing transmission congestion

 Notes:  Creation of regional transmission organizations (RTOs) is currently under rapid development. Under Order 2000, utilities

not currently members of an approved ISO must submit plans to join an RTO by October 2000. Utilities that are members of an

ISO must submit plans to form an RTO by January 2001.  MAPP and the Midwest ISO have reached an agreement to merge

operations. Mountain West is an independent system administrator which is considered an interim organization in a broader regional

transition plan.

 Source: Compiled from information obtained in trade journals and websites maintained by the regional transmission organizations.
76 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Table 13. Selected Information on Independent System Operators

California

 ISO

ERCOT

Texas ISO ISO New England MidWest ISO (MISO) New York ISO

Pennsylvania,

New Jersey,

Maryland

(PJM)%ISO

Operating Date March 31, 1998 August 1996 1997 Approved 1998.

Not yet operating

1999 April 1998

States Covered California Texas Connecticut,

Maine, 

Massachusetts,

New Hampshire,

Rhode Island,

Vermont

Illinois, Indiana,

Kentucky, Missouri,

Ohio, Maryland,

Pennsylvania,

Virginia, 

West Virginia,

Wisconsin

New York, 

New Jersey

Delaware, 

New Jersey,

Maryland,

Pennsylvania,

Washington, DC,

Virginia 

Number of

Transmission

Owners

3 16 15 13 8 10

Type of Organization Nonprofit Nonprofit Nonprofit Nonprofit Nonprofit Nonprofit

Board of Directors 24 members

representing 13

stakeholder classes

18 members

representing 6

stakeholder

classes

10 independent

members

8 independent

members

10 independent

members

8 independent

members

Control Areas Single Multiple Single Multiple Single Single

Transmission Rights

Program

Under development None Under

development

Undecided Transmission

congestion

contracts

Fixed

transmission

rights

Transmission

Congestion

Management

Price based a Priority based Priority based Priority based Price based Price based

Transmission Access

Charges b

 (Method to

Meet Revenue

Requirements)

Charge is based on

the embedded cost

of the transmission

owner serving the

customer

System-wide

(postage stamp)

charge

Charge is based

on the embedded

cost of the

transmission owner

serving the

customer

Charge is based on

the embedded cost of

the transmission

owner serving the

customer

Charge is based

on the

embedded cost

of the

transmission

owner serving

the customer

Charge is based

on the embedded

cost of the

transmission

owner serving the

customer

Ancillary Services ISO procures if not

provided

ISO coordinates ISO can provide ISO will arrange for

services

ISO can provide ISO provides or

coordinates

Transmission

Planning

ISO leads

coordinated process

ISO coordinates NEPOOL has lead

role

ISO develops plan

with transmission

owners

ISO is an active

participant

ISO prepares plan

Operation of a

Centralized Power

Market

Separate from ISO None Combined with ISO None Combined with

ISO

Combined with

ISO
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 77

Table 13. Selected Information on Independent System Operators (Continued)

California

 ISO

ERCOT

Texas ISO

ISO New

England

MidWest ISO

(MISO) New York ISO

Pennsylvania,

New Jersey,

Maryland

(PJM)%ISO

Type of Centralized Power

Markets

The California

power exchange

manages the dayahead and hourahead markets. 

The ISO manages

the ancillary

services, real-time

imbalance, and

congestion

markets.

None

One residual

day-ahead market

(only the

difference

between

participant's

energy resources

and obligations

can be bidded); 

All transactions

are priced at

ex-post energy

clearing price. 

None

Day-ahead and

real-time

market; both

ISO settled;

additional bids

can be submited

and

non-accepted

bids resubmitted

(hour-ahead

bids) up to 90

minutes before

dispatch hour in

the real-time

market.

One real-time joint

market for energy

and reserves;

generators submit

hourly bids for

their resources

once daily; these

resources are

used by the ISO

for energy and

reserves.

 a

Price based means that the ISO calculates the costs of congestion and allocates these costs to the appropriate transmission user. 

Priority based means that the ISO curtails power generation based on a predetermined curtailment plan.

 b

All of the ISOs will be phasing in one system-wide transmission access charge. 

 Sources: L.D. Kinsch, “Pricing the Grid: Comparing Transmission Rates of the U.S. ISO,” Public Utilities Fortnightly (February 15, 2000). Energy

Information Administration, The Changing Structure of the Electric Power Industry: Selected Issues 1998, DOE/EIA-0562(98) (Washington, DC, July

1998), pp. 34-35.

using energy prices is a relatively new and innovative

application, and it is likely that RTOs now being formed

will experiment with these new techniques.

Four of the regions&California, PJM, New York, and

New England&have established centralized markets for

buying and selling energy in their respective regions. In

California, the California Power Exchange, which is a

separate organization from the California ISO, runs their

energy market. Operation of the energy markets and the

ISO are combined in the other regions. These centralized

markets are new, and the rules of operation will likely

evolve as more operating experience is acquired.

With respect to meeting the requirements of Order 2000,

ISOs have until January 1, 2001, to submit a filing to

FERC specifying their plans for forming an RTO. None

of the existing ISOs have announced publicly their

specific compliance plans. It is unlikely that the existing

organizational structure of these ISOs will satisfy all of

the minimum characteristics and minimum functions

required of an RTO (Table 12), so one can expect to see

changes in the ISO organizational structures and

functions over the coming years. Electric utilities not

currently members of an ISO have to file plans to form

an RTO by October 1, 2000. In some regions, progress

toward compliance with Order 2000 has been made as

demonstrated by the following examples.

 The most significant announcement was the

planned merger between the Midwest ISO and the

Mid-Continent Area Power Pool (MAPP). This

arrangement has the potential of creating one RTO

from east of the Rocky Mountains up to the border

of the PJM ISO (Figure 27).

 The Southwest Power Pool (SPP) has filed with

FERC seeking formal recognition as an ISO. It also

requested that the Commission recognize that it

satisfies minimum requirements for an RTO. In

May 2000, FERC ruled that SPP’s proposal does

not have the operational authority, independence,

and other requirements to qualify as an RTO.

 In June 1999, the Alliance Companies, consisting of

five large IOUs located in Michigan, Ohio, and

Virginia, filed with FERC an application to transfer

their transmission facilities to a Transco. FERC

conditionally approved the transfer of ownership

and the general framework of the Transco as

meeting the requirements of an ISO subject to

certain revisions. In May 2000, FERC ruled that the

Alliance Transco does not meet the independence

requirements of an RTO.
78 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

94 A detailed discussion of horizontal market power and its effects on competition can be found in a report prepared by the U.S.

Department of Energy, Office of Economic, Electricity, and Natural Gas Analysis, “Horizontal Market Power in Restructured Electricity

Markets,” DOE/PO-0060 (Washington, DC, March 2000).

 Recently, FERC accepted the creation of Mountain

West as an Independent System Administrator

(ISA) and conditionally approved the transfer of

transmission facilities belonging to Nevada Power

and Sierra Power to the ISA. FERC did not

evaluate Mountain West under its ISO or RTO

principles. Mountain West is considered an

interim step in a broader regional transition plan

in the western region. 

 In response to FERC’s Order 2000, nine transmission-owning utilities are working together to

form the Northwest RTO.

Wholesale Electricity Trading Hubs

and Power Exchanges

Coinciding with FERC’s promotion and approvals of

market-based rates for the sale of electricity, the industry

has experienced a significant change in the way power

is sold. Most noticeable is the emergence of centralized

power markets where electricity suppliers submit bids

to sell power in regional markets. The market operator

evaluates the bids and selects the most economical bid

to meet energy demand in the region. Four centralized

power markets are now operating&California PX, New

York ISO, ISO New England, and PJM-ISO (Figure 28).

Of the four operating markets, the California Power

Exchange may be the most active because California’s

three major electric utilities were until recently required

by State law to sell all of their power through the

exchange. Participation in the other power markets is

voluntary and currently most of the power in these

regions is sold through bilateral arrangements between

buyer and seller. This may change as buyers and sellers

gain more experience with centralized power markets.

To support bilateral power trading, numerous electricity

trading hubs have emerged over the past few years. A

hub is a location on the power grid representing a

delivery point where power is sold and ownership

changes hands. Potentially, each control area on the

power grid could become a trading hub, but a few hubs

account for the bulk of power trading (Figure 28). Of the

10 major trading hubs, five of them are located in the

western United States, four in the midwest, and one in

the east.

Part of the reason that these major trading hubs have

emerged is because the New York Mercantile Exchange

(NYMEX) and the Chicago Board of Trade (CBOT) have

developed and sponsored electricity futures contracts to

facilitate trading at these hubs. A futures contract is a

common risk management tool used in agricultural,

metal, and energy commodities markets. One of the

main purposes of a futures contract is to eliminate the

risk of price changes. For example, a power marketer

entering into a contract to sell power at a predetermined

price at the California Oregon Border (COB) runs the

risk that the price it must pay for electricity will increase

before the power is delivered. However, the power

marketer can hedge its risk by buying electricity futures

that match the quantity and timing of the original power

contract. NYMEX has created electricity futures

contracts for the Cinergy, COB, Entergy, Palo Verde,

and PJM trading hubs. CBOT has created electricity

futures contracts for the Commonwealth Edison and

Tennessee Valley Authority trading hubs.

Market Power in Wholesale

Electricity Markets

Market power is the ability of an electricity supplier to

raise prices profitably above competitive levels and

maintain those prices for a significant time. Electricity

suppliers exercising market power force consumers to

pay higher electricity prices than they would pay in a

competitive market.

Market power exists in two forms&horizontal and

vertical. Vertical market power may occur when a firm

controls two related activities. In the electric power

industry, one firm controlling both electricity generation

and transmission has the potential to exercise vertical

market power. Separating control of electricity generation from control of the transmission system (via ISOs

and RTOs) is designed to eliminate the potential for

vertical market power. Horizontal market power is more

difficult to eliminate. Horizontal market power may

occur when a firm controls a significant share of the

market. In the electric power generation business, one

firm controlling a significant share of electric generation

capacity in a particular region has the potential to

exercise horizontal market power. 94

FERC and State regulators are interested in seeing that

market power abuses do not undermine the potential

benefits of competitive markets. To meet this objective,

FERC requires ISOs and RTOs to monitor bulk power

markets for abuses and design flaws, and to report
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 79

95 California ISO, Department of Market Analysis, “Report on California Energy Market Issues and Performance: May-June 2000”

(August 2000).

X

X

X

X

X

X

X

Mid 

Columbia

California

Oregon

Border

(COB)

California

Power

Exchange

Mead

Palo

Verde

Four 

Corners

Comm onwealth

Edison

(ComEd)

Cinergy

Tennessee

Valley 

Authority

(TVA)

Pennsylvania, 

New Jersey, 

Maryland (PJM) ISO

and

Trading Hub

New York 

ISO 

ISO New 

England

Entergy

X

X

X Major wholesale electricity trading hubs.

Centralized power market. Unlike trading hubs, centralized power m arkets cover an entire 

region, and are not restricted to one location.

X

Figure 28. Major Wholesale Electricity Trading Hubs and Centralized Power Markets

market anomalies to FERC and other effected regulatory

authorities. This market monitoring function is critical,

particularly now as new competitive bulk power

markets develop across the country.

A report prepared recently by the California ISO’s

Department of Market Analysis demonstrates the crucial

role of market monitoring.95 The report documents that

recent spikes in California’s electricity prices over this

summer were attributable, in part, to some electricity

suppliers exercising market power. The report noted

that “the presence of market power can be verified by

bid prices significantly over the variable costs of many

suppliers in the ISO’s market.”

Price spikes in wholesale power markets in California

and New York have prompted FERC to conduct an

investigation of all electric bulk power markets to

determine whether they are working efficiently and, if

not, the causes of the problems. Their report is

scheduled to be completed November 1, 2000.

Conclusion 

By providing the capability to move power over long

distances, the transmission system is an integral component of the Nation’s electric power industry. Nondiscriminatory access to the transmission system for all

electricity suppliers is critical to creating competitive

power markets. For more than a decade, FERC has been

pushing for the development of competitive wholesale

power markets and opening the transmission system to

all qualified users. Since the late 1980s, FERC has

 Notes: Power trading also occurs at locations not indicated on the map. The New York Mercantile Exchange (NYMEX) has

established electricity futures contracts for the Cinergy, COB, Entergy, Palo Verde, and PJM trading hubs. The Chicago Board of

Trade has established electricity futures contracts for the ComEd and TVA trading hubs.

 Source: Electric industry trade journals and Internet websites.
80 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

approved more than 850 applications from electric

utilities, power marketers, and independent power

producers to use market-based rates to sell power competitively in wholesale markets. In 1996, the Commission

issued Order 888, which opened the transmission system

to all qualified power producers and marketers. Prior to

Order 888, independent power producers and power

marketers had difficulty accessing the transmission grid

to deliver power.

Over the past few years, FERC has also encouraged

regionalization of the transmission grid whereby vertically integrated electric utilities transfer control of their

transmission facilities to an independent transmission

organization. Independent means generally that the

transmission organization does not have an economic

interest in buying or selling electricity. The independence from the electricity market helps to ensure fair

and comparable access to the transmission grid. In

addition, regionalization of control of the transmission

grid promotes improved operating efficiency, simplified

and more efficient transmission pricing, and improved

reliability.

In an ambitious move to promote regional control of the

transmission system, FERC recently issued Order 2000

encouraging all electric utilities to transfer control

and/or ownership of their transmission facilities to an

independent RTO. Utilities that are not currently a member of an existing regional organization are required to

submit plans to join an RTO by October 2000; utilities

that are members of an existing regional organization

are required to submit their plans to join an RTO by

January 2001. It is possible that compliance with Order

2000 will reduce the ownership and control of the

Nation’s transmission grid to a handful of independent

transmission companies over the next few years, but

there is much uncertainty about the ultimate effects of

Order 2000.

Both this chapter and the preceding chapter have

discussed restructuring activities at the Federal level.

The following chapter examines the roles of the States.
Energy Information Administration/The Changing Structure of the Electric Power Industry 2000: An Update 81

96 California Public Utility Commission, Decision 92-90-088, W4, 43, “Order Instituting Investigation on the Commission’s Own Motion

to Implement the Biennial Resource Plan Update Following the California Energy Commission’s Seventh Electricity Report” (September

16, 1992). 97 Refer to California Public Utility Commission, California’s Electric Services Industry: Perspectives on the Past, Strategies for the Future

(San Francisco, February 1993). 98 California Public Utility Commission, “Order Instituting Rulemaking on the Commission’s Proposed Policies Governing

Restructuring California’s Electric Services Industry and Reforming Regulation and Order Instituting Investigation on the Commission’s

Proposed Policies Governing Restructuring of California’s Electric Services Industry and Reforming Regulation,” Docket Nos. R.94-04-031

and I.94-04-032 (April 20, 1994).

8. The Role of the States in Promoting Competition

In the years following enactment of EPACT, there has

been a surge of activity in State legislatures and at utility

commissions to examine various issues with respect to

the electric utility industry. Critical among them has

been a wide range of activities designed to promote

industry competition at the retail level and to complement the wholesale wheeling and stranded cost

initiatives of the Federal Energy Regulatory Commission

(FERC). In 1999, customers in 12 States could actually

choose their electricity supplier. In California, Rhode

Island, Massachusetts, and New Jersey almost all

customers had the right to choose. In Arizona,

Delaware, Illinois, Michigan, Montana, New Hampshire,

and New York customer choice is still being phased in.

In Pennsylvania, where two-thirds of customers could

choose in 1999, as of January 1, 2000, all customers can

choose their electricity supplier.

Regulatory Activities

Not all State commissions have moved with the same

zeal, even though most of them have under consideration the merits and implications of competition,

deregulation, and electric utility industry restructuring.

States with high electricity rates, such as California and

those in the Northeast, have had compelling reasons to

promote competition in the hope of making lower rates

available to their customers in general.

As an example, the California Public Utility Commission

(CPUC) directed an examination of the comprehensive

set of regulatory programs to explore alternatives to

what was then the current regulatory approach based on

conditions and trends identified in its Decision No. 92-

09-088 of September 1992.96 The directive resulted in the

submission of a staff report&generally known as the

“Yellow Book”&to the CPUC in February 1993.97

The “Yellow Book” study concluded that the State

should reform its regulatory program, including a

redefinition of the prevailing regulatory compact, and

offered strategies to address shortcomings of its

regulatory framework. Based on a comprehensive reexamination of the electric utility industry in the State

and the regulatory policy under which the industry

functioned, the CPUC opened rulemaking and investigative proceedings to consider its proposed restructuring

policies in early 1994.98 These initiatives, popularly

known as the “Blue Book” proposals, outlined a strategy

to replace the traditional cost-of-service regulatory

framework with alternatives that focused on utility

performance and, where possible, the discipline of the

market. Subsequent regulatory and legislative activities

in California will be presented in more detail as one of

the five case studies that follow later in this chapter. 

Other States have not moved with such enthusiasm,

however. In December 1998, 23 State public utility commissions sent Congress a letter expressing concerns that

issues affecting them may not be given adequate consideration in the debate about restructuring. Kentucky,

whose electricity prices are the lowest east of the Rocky

Mountains, is one of these States. Recently, Kentucky’s

Special Task Force on Electricity Restructuring concluded that there are no compelling reasons to

restructure their electric power industry. 

States such as Idaho and Nebraska have taken the view

that the main tenets of EPACT (as pertaining to promoting competition) are difficult for them to implement.

The Idaho Public Utilities Commission (IPUC), for

example, has stated that it is not its role to actively

attempt to bring about deregulation of the industry. The

IPUC expressed the concern that rates in Idaho could go
82 Energy Information Administration/The Changing Structure of the Electric Power Industry 2000: An Update

99 Idaho Public Service Commission’s Order No. 26555, Case No. GNR-E-96-1, “In the Matter of the Commission’s Investigating into

Changes Occurring in the Electric Industry” (August 16, 1996). 100 Note that Nebraska has no privately owned electric utilities. All generation, transmission, and distribution service in Nebraska is

provided by public entities, municipalities, and cooperatives whose governing boards are responsible to, and serve at the voting pleasure

of, rate-paying Nebraska residents. 101 Nebraska Public Power District, 1999 Annual Report, p. 5. 102 Energy Information Administration, State Electricity Profiles, DOE/EIA-0629 (Washington, DC, March 1999). 103 On July 3, 1995, Legislative Resolve to Require a Study of Retail Competition in the Electric Industry became Maine law. This

legislation directed the Maine Public Utilities Commission (MPUC) to undertake a study to develop at least two plans for an orderly

transition to a competitive market. The MPUC released its draft report on July 19, 1996. 104 The New Hampshire legislature, for example, passed legislation in June 1995 directing the New Hampshire Public Utility

Commission (NHPUC) to establish a pilot program to examine the implications of retail competition. In its order establishing preliminary

guidelines for a retail competition pilot program, the NHPUC noted that the program was not necessarily a step toward wide-scale

competition but was rather a way to examine the implications of an obstacle to a competitive retail market at a time when supply shortages

are not a concern. Subsequent legislation (HB-1392), enacted in May 1996, directed the NHPUC to undertake a generic proceeding to

develop and establish a final order establishing a statewide electric utility restructuring plan no later than February 28, 1997. 105 Arizona, Arkansas, California, Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, Montana, Nevada, New

Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Oregon, Pennsylvania, Rhode Island, Texas, Virginia, and West Virginia. 106 Alabama, Colorado, Florida, Indiana, Iowa, Louisiana, Minnesota, Mississippi, Missouri, North Carolina, North Dakota, Utah,

Vermont, Washington, Wisconsin, and Wyoming. 107 Georgia, Hawaii, Idaho, Kansas, Kentucky, Nebraska, South Dakota, and Tennessee.

up, and, at the same time, deregulation could result in

the diminution of the quality of service enjoyed by the

ratepayers in the State.99 The Nebraska Public Power

District (NPPD) maintains that applying reciprocity

requirement provisions of FERC Order 888 violates

Nebraska’s law and its constitutional rights.100 The

NPPD has, however, continued to monitor the development of regional transmission organizations and

independent transmission companies. NPPD has created

a new position&Vice President of Transmission

Services&to focus on restructuring outside its boundaries and how external activities might affect NPPD.101

In 1996, Idaho, Kentucky, and Nebraska ranked first,

second and twelfth, respectively, in lowest average

revenue per kilowatthour.102 In 1998, they ranked first,

third and ninth, respectively. It is not surprising that

they are not the States that are leaders in the restructuring movement.

Like California, Kentucky is one of the five States that

will be examined in detail later in this chapter. The

others are Massachusetts, Pennsylvania, and Texas.

Massachusetts and Pennsylvania were chosen because

they, like California, were among the earliest States to

embrace restructuring although they have had vastly

different experiences. Texas was chosen because it is a

large State that is in the planning stage for instituting

competition.

Legislative Activities

All State utility commissions typically enjoy broad

regulatory authority to ensure that electric utilities in

their jurisdictions provide fair, just, and reasonable

electricity rates to their customers. In addition, State

commissions are also empowered to regulate various

other aspects of power generation, transmission, and

distribution at the State level. However, not all commissions may be endowed with the necessary legal

authority to manage an evolving competitive market

structure. Accordingly, legislation in some States is

designed primarily to grant the utility regulatory agency

the authority to address the restructuring issues or to

consider alternative rate-making processes (incentive- or

performance-based regulation). Elsewhere, State legislators show a serious interest in finding out how the

State could respond to new competitive pressures

emerging in the electric industry.103 Exploratory activities may also be promoted at the behest of the State

legislators in an effort to gain additional insights.104 In

some cases, legislative actions may become necessary to

adopt decisions recommended by the commission(s) for

implementation.

As of July 1, 2000, 24 States105 and the District of Columbia had enacted legislation or passed regulatory orders

to restructure their electric power industries. Alaska and

South Carolina had legislation or regulatory orders

pending. Sixteen States106 still had ongoing legislative or

regulatory investigations, and there were 8 States107

where no restructuring activities had taken place (Figure

23).

Case Studies

This section presents the current status of restructuring

in five States: California, Kentucky, Massachusetts,

Pennsylvania, and Texas. California, Pennsylvania, and
Energy Information Administration/The Changing Structure of the Electric Power Industry 2000: An Update 83

108 Energy Information Administration, State Electricity Profiles, DOE/EIA-0629 (Washington, DC, March 1999), p. 29. 109 California Public Utility Commission, “Plug In, California!,” http://www.cpuc.ca.gov/divisions/csd/electric/

PlainEnglish981030.htm. 110 Energy Information Administration, “An Overview of the Electric Power Industry,” presentation to staff of the U.S. Senate Committee

on Energy and Natural Resources (March, 2000). 111 California Public Utility Commission, http://www.cpuc.ca.gov/electric_restructuring/esp_registration/providers/esp_udc.htm. 112 California Public Utility Commission, “Plug In, California!,” http://www.cpuc.ca.gov/divisions/csd/electric/

PlainEnglish981030.htm. 113 Energy Information Administration, “Status of State Electricity Industry Restructuring Activity: Stranded Costs as of May 2000,”

http://www.eia.doe.gov/cneaf/electricity/chg_str/tab5rev.html#CA. 114 California Energy Commission, “Electricity Industry Restructuring % What it is and will it affect me?,” http://www.energy.ca.gov/

restructuring/restructure_FAQ.html. 115 California Public Utility Commission, “Plug In, California!,” http://www.cpuc.ca.gov/divisions/csd/electric/

PlainEnglish981030.htm.

Massachusetts were chosen because they were among

the first States to institute restructuring at the retail level

and they did so differently. Texas has recently passed

restructuring legislation and its utilities and public

utility commission are planning for competition which

will begin in 2002. Kentucky was chosen to serve as an

example of a State that has done little to restructure; in

fact, current policy is to maintain the status quo and put

off restructuring until there is a compelling reason to do

so.

California

In 1996, the average revenue per kilowatthour (which is

used as a proxy for price) of electricity sold in California

was 9.48 cents,108 the tenth highest rate among the 50

States and the District of Columbia. This rate was one

factor leading Governor Pete Wilson to sign Assembly

Bill 1890 (AB1890) on September 23, 1996. This new law

established a 4-year transition period to make the State’s

electric power industry competitive. To implement it,

retail competition, allowing customers to choose their

electricity, began on March 31, 1998. Rates were frozen

at the levels in effect as of June 10, 1996, and a 10-percent

rate reduction was guaranteed for residential and small

commercial users.109 These rates will remain frozen until

March 31, 2002. As of December 31, 1999, the State has

209,752 direct access customers. This number represents

2.1 percent of the total number of eligible customers and

13.8 percent of the total load.110 Industrial customers,

who generally use more electricity than residential

customers, account for a major share of this load. These

customers are currently served by 35 electric service

providers registered with the CPUC.111

AB1890 also contained provisions for the creation of an

independent system operator (ISO) and a legally

separate power exchange (PX) out of concern about

market power issues. To ensure that utilities do not

continue their traditional monopolistic advantage by

controlling generation, transmission and distribution,

the ISO and PX are independent of the utilities.112 The

law allows for stranded cost recovery in California.

Utilities may apply the difference between their actual

operating costs and the frozen rate toward recovering

their stranded costs. A “Competition Transition Charge”

based on the sales volume appears on consumers’ bills

along with another charge that finances the bonds that

provided the rate reduction.113 A subsequent law

requires retail suppliers to disclose the sources of generation to customers; report fuel types and consumption to

system operators who will make the information available to the California Energy Commission; and report

emissions, purchased power, losses, and retail sales.114

The California ISO received FERC approval in October

1997, and became operational on March 31, 1998. The

major responsibility of the ISO is to ensure fair and

impartial access to the high-voltage transmission system

for all generators, while maintaining reliable operation.

The transmission system will continue to be owned by

the investor-owned utilities (IOUs). The ISO will ensure

that no particular buyer or seller of electricity can block

access by others. Generators who ship electricity

through the system will pay a fee to cover the system

costs and to ensure reliability.115

The PX, regulated by FERC, also became operational on

March 31, 1998. It serves as an auction market for the

buying and selling of electricity. The three largest IOUs

in the State&Pacific Gas & Electric (PG&E), Southern

California Edison (Edison), and San Diego Gas &

Electric (SDG&E)&must sell their power to the PX. If

they wish to, municipalities, independent power

producers, irrigation districts, and out-of-state producers may also sell power to the PX. 

The PX accepts requests to buy a quantity of electricity

at a given price. The PX functions like an auction to

match total demand for power with generation of

power. It creates a spot market where price information
84 Energy Information Administration/The Changing Structure of the Electric Power Industry 2000: An Update

116 Ibid. 117 American Public Power Association, Public Power Daily (May 18, 2000). 118 Florida Public Service Commission, “Electric Restructuring Activities Update,” http://www.psc.state.fl.us/general/publications/

restruc.htm. 119 The Electricity Daily, Vol. 14, No. 98 (May 22, 2000). 120 California Energy Commission, “Electric Generation Divestiture in California,” http://www.energy.ca.gov/electricity/

divestiture.html. 121 The Energy Report (Arlington, VA: Financial Times Energy, January 3, 2000), p. 5. 122 Energy Information Administration, “Status of State Electricity Industry Restructuring Activity as of May 2000,”

http://www.eia.doe.gov/cneaf/electricity/chg_str/tab5rev.html#CA. 123 California Independent System Operator, Report on California Energy Market Issues and Performance, May-June 2000 (August 10, 2000),

p. I.

is publicly available. The PX then solicits bids from

electricity generators and chooses the lowest bidders

until it has enough supply to meet the requests to buy

power. The prices change on an hourly basis.116

PG&E, Edison, and SDG&E were ordered to buy their

power from the PX for 4 years after its inception to resell

to customers who buy electricity from the utility distribution companies. They will pay a price determined by

the PX based on the market demand for power. This was

done to foster fair competition between utilities and

other electricity suppliers.

However, in a recent development, California regulators

are poised to amend the requirement that the State’s

IOUs buy all their power through the PX. The Automated Power Exchange of Santa Clara and other rivals

have consistently opposed the mandate that the IOUs

buy from the PX and they have won support from two

commissioners, Josiah Neeper and Richard Bilas. They

have introduced a proposal that would allow utilities to

buy from any approved exchange.117

AB1890 established a public benefit program for low

income assistance, energy efficiency, research and development programs, and programs to encourage renewables. It was anticipated that approximately $540 million

would be collected over 4 years by a non-bypassable

wires charge.118 Approximately 30 local governments

have switched to Commonwealth Energy, which is

supplying geothermal energy from Lake, Sonoma, and

Imperial counties. Santa Monica, in Los Angeles County,

is currently the world’s largest all-renewable city, but

Oakland is considering making purchases that would

put it in the global lead.119

PG&E, Edison, and SDG&E have divested a large

amount of generating capacity to address concerns

about market power. To date PG&E has divested itself

of 7.4 gigawatts of capacity at a sale price of $1.5 billion.

Edison has sold 10.6 gigawatts for $1.2 billion. SDG&E

has completed transactions of 2.1 gigawatts for $475 million.120 California has been cited as “leading the way

with merchant plant proposals.” The California Energy

Commission approved three merchant plant proposals

in 1999, has seven applications under review, and

anticipates 11 more proposals.121

In June 1999, the CPUC began public hearings on

opening distribution to competition. The formal opening

of the proceeding in December 1998 resulted in

responses from numerous stakeholders. Some have

suggested waiting until competition in the generation

market has matured before attempting to open distribution to competition.122

The California electricity market was in turmoil during

the summer months of 2000. There were periods of

rolling blackouts around the San Francisco area. Prices

in the San Diego region more than doubled. A scorching

summer exacerbated these conditions. Some stakeholders have called to re-regulate the industry, while

others have called for market reforms. In the meantime,

the California ISO set price caps to contain wholesale

prices over the summer. The cap was initially set at $750

per megawatthour and was lowered to $250 per megawatthour in August 2000.

California’s high electricity prices have been linked to

three causes: a deficiency of generating capacity in

California; a market system that does not permit enough

forward market trading as a means of managing supply

and demand risk; and a system that does not allow

sufficient customer response to high prices. The

California ISO sees improving consumer response to

increasing prices and opening the market to new

electricity suppliers as fundamental solutions to the

recent instability.123

Government executives and agencies have offered shortterm relief to high prices. On August 2, 2000 Governor
Energy Information Administration/The Changing Structure of the Electric Power Industry 2000: An Update 85

124 “California Looks in Every Direction Seeking ‘Fix’ for Market Shock,” Electric Utility Week (The McGraw-Hill Companies, August

7, 2000), p. 7. 125 The Energy Report (Arlington, VA: Financial Times Energy, August 28, 2000), p. 1. 126 American Public Power Association, Public Power Daily (September 22, 2000). 127 Energy Information Administration, State Electricity Profiles, DOE/EIA-0629 (Washington, DC, March 1999), p. 263. 128 Public Utility Commission of Texas, Electric Competition Overview, http://www.puc.state.tx.us/ocp/competition/echome.cfm. 129 The Energy Report (Arlington, VA: Financial Times Energy, January 3, 2000), p. 4. 130 Electric Utility Week (New York: McGraw-Hill, January 17, 2000) p. 7. 131 Dallas Morning News (April 1, 2000), http://www.dallasnews.com.

Gray Davis issued three executive orders aimed at

stabilizing prices, increasing supply, and reducing peak

demand.124 The Low Income Home Energy Assistance

Program and the Small Business Administration

released more than $2 million in emergency funds to

assist low-income households and small businesses in

the San Diego area.125

Responding to San Diego Gas & Electric’s petition to

reduce wholesale prices, FERC ordered a hearing on

August 23, 2000 to investigate if the electricity rates are

just and reasonable. Should FERC conclude that the

rates were unreasonable, it could order refunds under

authority granted by the Federal Power Act for sales that

occurred after August 23. Subsequently, on September

21, FERC Chairman James Hoecker asked Congress for

greater authority “to retroactively correct extraordinary

wealth transfers” since the agency has limited authority

to order refunds.126

Texas 

Much of Texas is unique in that it is not subject to the

control of FERC. As stated in Chapter 3, the United

States has three separate power grids connected by a

few direct current tie lines: the Eastern Interconnect, the

Western Interconnect, and the Texas Interconnect.

Utilities within each interconnection coordinate operations and planning and buy and sell power among

themselves. Because utilities in the Texas Interconnected

System are not connected with other utilities outside the

State and electric trade does not cross State boundaries

for these utilities, FERC does not have regulatory

jurisdiction over them. In 1998, Texas was near the

middle of the rankings of all States and the District of

Columbia with respect to electricity rates. In 1998, the

average revenue per kilowatthour was 6.07 cents, which

ranked as the 25th lowest in the country. With prices in

the middle of the range of States, it is not surprising that

Texas recently passed restructuring legislation.

In 1995, Senate Bill 373, which became the Public Utility

Regulatory Act of 1995, was enacted to restructure the

wholesale electricity market in Texas consistent with

FERC requirements for unbundled transmission service.

The law also required the establishment of an ISO. The

ISO in the Electric Reliability Council of Texas (ERCOT)

differs somewhat from the other ISOs. The ERCOT ISO

does not participate in generation dispatch, in power

exchanges, in providing ancillary services, or in establishing prices other than determining the cost of any

redispatch needed to allow transactions to occur. In

1996, the Public Utility Commission (PUC) of Texas

issued rules implementing the legislation that required

transmission-owning utilities in the State to provide

open access to the transmission system and ancillary

services. The rule also required separation of transmission, distribution, and generation costs and rates,

and the establishment of the ERCOT ISO.127

In 1999, Texas was the largest State to pass restructuring

legislation. Governor George W. Bush signed Senate Bill

7 to introduce retail competition to Texas.128 Retail

choice will begin in 2002. The restructuring law freezes

rates for 3 years or until 40 percent of a utility’s

customers have switched to an alternate provider,

whichever comes first. The law is expected to give a

boost to development of renewable energy sources.

Utilities can recover an estimated $9 billion in stranded

costs through securitization. In response to the law, TXU

and Southwestern Public Service have already put some

of their power plants up for sale.129 Electric cooperatives

and municipally owned utilities are exempt from

customer choice unless their governing boards decide to

open their markets to competition. 

As of January 10, 2000, all Texas IOUs had filed detailed

plans describing how they propose to unbundle their

operations.130 As of March 31, 2000, nine utilities had

turned in their transition plan proposals to the PUC.131

Utilities were required to state which aspects of their

businesses would be deregulated and which portions

would remain regulated. The companies were also

required to describe how they would separate their

businesses into a retail provider, a generation company,

and a transmission and distribution utility. The electric
86 Energy Information Administration/The Changing Structure of the Electric Power Industry 2000: An Update

132 U. S. Department of Energy, Electric Utility Restructuring Weekly Update, http://www.eren.doe.gov/electricity_restructuring/

weekly/apr7_00.html. 133 U. S. Department of Energy, Electric Utility Restructuring Weekly Update, http://www.eren.doe.gov/electricity_restructuring/

weekly/jan21_00.html. 134 U. S. Department of Energy, Electric Utility Restructuring Weekly Update, http://www.eren.doe.gov/electricity_restructuring/

weekly/feb25_00.html. 135 Ibid. 136 U.S. Department of Energy, Electric Utility Restructuring Weekly Update, http://www.eren.doe.gov/electricity_restructuring/

weekly/jan7_00.html. 137 Foster Electric Report, No. 176 (October 20, 1999), p. 3. 138 States’ Electric Restructuring Activities Update, Florida Public Service Commission, http://www.psc.state.fl.us/general/publications/restruc.htm. 139 Energy Information Administration, “Status of State Electricity Industry Restructuring Activity as of May 2000,”

http://www.eia.doe.gov/cneaf/electricity/chg_str/tab5rev.html. 140 The Energy Report (Arlington, VA: Financial Times Energy, January 3, 2000), p. 5.

companies were required to report the fees they would

charge to retail competitors using the utilities’ lines.132

By September 2001, the PUC will begin to certify retail

electricity providers. The Texas Pilot Program is

scheduled to commence on June 1, 2001, and on January

1, 2002 retail choice is slated to begin with small

commercial customer and residential electric rates

decreasing by 6 percent. A proposal for a consumer

education plan has been approved by State regulators.

This marks the first step in implementing a consumer

plan mandated by the restructuring law. The intent of

the plan is to explain restructuring to customers and

inform them of their options. Plans for northeastern

Texas have been developed, and the PUC will strive to

develop a plan with emphasis on non-English speaking

and lower-income customers. The plan will most likely

be implemented by early 2001.133

The Texas approach to implementing competition has

been cited as a good model for restructuring. The

decision to deal with wholesale issues at the outset by

leveling the playing field for equal transmission access

“promises to create a strong retail market,” according to

one energy consultant.134 A spokesperson for another

energy company, however, believes that a serious flaw

in the restructuring plan is the local control of metering

and billing until 2004.135

With regard to renewables, a new rule mandates the

building of 2 gigawatts of new capacity fueled by renewable sources by 2009. Between now and 2009 the rule

requires the following: 400 megawatts by 2003, an

additional 450 megawatts by 2005, another 550 megawatts by 2007, and an additional 600 megawatts by 2009.

January 1, 2002, will mark the beginning of a Renewable

Credits Trading Program in the State, which will

continue until 2019. Retailers with insufficient credits

will be penalized $50 per megawatthour or 200 percent

of the average cost of traded credits of the year.136

Massachusetts 

On November 27, 1997, HB 5117, the Electric Utility

Restructuring Act, was signed by Governor Paul

Cellucci to restructure the industry in Massachusetts.

The law basically affirmed the PUC restructuring order

of 1996. The Restructuring Act mainly affects the

Commonwealth’s eight investor-owned distribution

companies, which supply 87 percent of the electricity in

Massachusetts.137 Retail access was required by March

1998, and a simultaneous rate cut of 10 percent to be

followed 18 months later by an additional 5 percent cut

was made law. Municipal utilities have the option to

participate.138 Additionally, the divestiture of generation

assets was encouraged.139 In 1996, Massachusetts had the

eighth highest electricity rates in the Nation, which were

most certainly a consideration in enacting the legislation

the following year. In 1998, the rates in the Commonwealth were the ninth highest in the country. Between

1996 and 1998, the nonutility share of capability

increased from 16 percent to 67 percent as utility

divestitures took place. So far, however, the number of

customers that have switched is not high. A slowly

increasing standard offer rate (described below) could

lead to increases in customers in the future.140

Three generation service options are available to consumers: (1) Standard Offer Service, provided by

distribution companies; (2) Default Service, provided by

distribution companies; and (3) Competitive Generation

Service, provided by competitive suppliers. The price

the customer pays for generation service is dependent

on the type of service that the customer receives.

Standard Offer Service is a transition generation service

available through 2004 to each distribution company’s

customers of record. The price of the Standard Offer

Service is set in advance and will increase gradually. As

examples, the Standard Offer Rates for the Boston
Energy Information Administration/The Changing Structure of the Electric Power Industry 2000: An Update 87

141 Initially the Standard Offer rates for each of the Massachusetts distribution companies approved by the Department of

Telecommunications and Energy was equal to 2.8 cents per kilowatthour. The rate for each of these companies remained at 2.8 cents for

the remainder of 1998, with two exceptions: (1) Boston Edison increased its Standard Offer rate to 3.2 cents on June 1, 1998, concurrent with

the completion of the divestiture of its non-nuclear generating units; and (2) Massachusetts Electric Company increased its Standard Offer

rate to 3.2 cents on September 1, 1998, concurrent with the completion of the divestiture of New England Power Company’s non-nuclear

generating units. 142 Massachusetts Department of Telecommunications and Energy, Electric Restructuring in Massachusetts,

http://www.magnet.state.ma.us/dpu/restruct/competition/index.htm. 143 Electric Utility Week (New York: McGraw-Hill, January 17, 2000) p. 8. 144 Ibid.

Edison Company and the Cambridge Electric Light

Company rose from 3.69 cents and 3.5 cents per

kilowatthour to 4.5 cents and 3.8 cents per kilowatthour,

respectively, from 1999 to 2000.141 A customer that did

not select a competitive supplier as of March 1, 1998,

automatically was placed on the Standard Offer Service.

(Customers who move into a distribution company’s

service territory after March 1, 1998, are not eligible to

receive the Standard Offer&these customers are placed

on Default Service until they select a competitive

supplier.) In general, once customers select a competitive supplier, they are no longer eligible to return to

the Standard Offer Service. Exceptions include (1) lowincome customers who can return at any time, (2)

residential and small commercial and industrial

customers who return within 120 days of deleting a

supplier (This option was available only until March 1,

1999.), and (3) customers participating in a municipal

aggregation program who return within 180 days of

joining the program. The rates for the Standard Offer

Service are regulated by the Department of Telecommunications and Energy (DTE) and were set at levels

that provided a 10 percent overall bill reduction to

customers receiving the Standard Offer Service. The

level of the overall bill reduction for the Standard Offer

customers increased to 15 percent on September 1, 1999.

Default Service is the generation service provided by

distribution companies to those customers who are not

receiving either Competitive Generation or Standard

Offer Service. Customers who moved into a distribution

company’s service territory after March 1, 1998, received

Default Service until they selected a competitive

supplier. Prices for Default Service are regulated by the

DTE and may not exceed the average market price for

electricity in New England.

Competitive Generation Service will be provided by

competitive suppliers and electricity brokers that have

been licensed by the DTE. A competitive supplier is

defined as licensed to sell electricity and related services

to customers. As of May 2000, 33 authorized competitive

suppliers/electricity brokers were located in Massachusetts. An electricity broker is an entity that is licensed

to facilitate or otherwise arrange for the purchase and

sale of electricity and related services to customers, but

is not licensed to sell electricity to customers. An

applicant for a competitive supplier or electricity broker

license must demonstrate, among other things, the

financial and technical capability to provide the

applicable services. Prices for Competitive Generation

Service will be set by the competitive electricity marketplace; these prices will not be regulated by the DTE.

Customers receiving generation service from a competitive supplier have two billing options: (1) complete

billing, where a customer receives a single bill from the

distribution company, including charges for generation

service, and (2) pass-through billing, where a customer

receives two bills&one from the distribution company

for non-generation charges and another from the

competitive supplier for generation service charges.142

An assessment of the first year of electric utility industry

restructuring in Massachusetts shows that the largest

accomplishment was the mandated reduction in overall

customer bills by 10 percent. However, little retail competition has resulted due to the low Standard Offer. In

fact, between February and March 2000, the number of

customers buying competitive power dropped by 1,100.

Of the 2.5 million electric accounts in the Commonwealth, only 7,302 are buying power competitively.143

Energy Commissioner David O’Connor has stated that

the problem lies in the region’s volatile wholesale power

market, which has seen significant price spikes. High

wholesale prices have led to high retail prices and

consequently, commercial and industrial customers,

whose competitive power contracts are expiring, are

opting to go back to low-price utility service.144

To address the problem, the DTE has proposed two

market-based pricing options to remove the incentive for

customers to return to default service. The first offers

customers a fixed price for 6-month periods. It would be

available to all customers who are already on default

service when the 6-month period begins, or who moved

into the service territory after the period begins. The

price would be based on the average monthly wholesale
88 Energy Information Administration/The Changing Structure of the Electric Power Industry 2000: An Update

145 Electric Utility Week (New York: McGraw-Hill, January 17, 2000) p. 1. 146 Electric Utility Week (New York: McGraw-Hill, January 17, 2000) p. 9. 147 The Act authorizes the Massachusetts Industrial Finance Agency to issue “electric rate reduction revenue bonds,” to finance the

buy-out by electric companies of purchased power contracts with above-market rates. 148 Florida Public Service Commission, “States’ Electric Restructuring Activities Update,” http://www.psc.state.fl.us/general/

publications/restruc.htm. 149 Ibid. 150 Energy Information Administration, State Electricity Profiles, DOE/EIA-0629 (Washington, DC, March 1999), p. 234.

price that each utility pays for supply. The second option

would allow default service price to change monthly,

based on the monthly wholesale prices that each utility

pays for its default service supply. This option would be

available to customers who begin receiving the service

after the start of the 6-month period and who were

previously receiving their electricity from a competitive

supplier.145

Paul Gromer, an attorney with the Boston-based Peregrine Energy Group, which represents the independent

power marketers operating in the Commonwealth, states

the problem lies in the fact that one default service rate

exists for all customers. He argues that this creates crosssubsidization and inaccurate pricing signals. He contrasts what is happening in Massachusetts with the way

Connecticut, Pennsylvania, New Jersey, California, and

Maine have offered different rates for different customer

classes.146

Major changes are, however, taking place even though

competitive supply is hardly pervasive throughout the

Commonwealth. For example, utility companies made

significant progress in divesting their power plants and

power supply contracts. The generation portion of the

electric industry is now virtually all owned by independent power producers. This extensive sale of power

plants has significantly reduced the stranded cost

obligations that would have been facing ratepayers.

Massachusetts had awarded stranded costs if conforming utilities had demonstrated that they had

divested all non-nuclear generation and attempted to

mitigate all other costs. So far, approximately $2 billion

of the total $6 billion that will eventually be paid has

been transferred. Securitization then becomes permissible.147 If a utility had been unwilling to divest its

generation, the DTE would have determined the level of

stranded costs.

ISO New England received conditional FERC approval

on June 25, 1997. Utilities in all six New England States

created the ISO through a voluntary agreement.148

Additionally, proposed construction of more than 30

gigawatts of new power plants has been announced

across the region, prompted by restructuring legislation

enacted in most of the New England States. While not all

proposals will come to fruition, it is likely that the

increased competition from these new plants will force

some of the existing, less efficient plants into retirement.

Most of the new capacity will be fueled by natural gas

and other low emission fuels; therefore air pollution

should be lowered and customers will have the option

to buy greener power from sources close to home.

With respect to public benefit programs, distribution

companies must offer low income discounts. A Renewable Energy Trust Fund was established with a fee of

0.125 cents per kilowatthour in 2000. Also, a charge of

0.33 cents per kilowatthour has been established for

funding energy efficiency programs. The fee will be

phased down to 0.25 cents per kilowatthour in 2002. 

A renewable portfolio standard is mandated, and hydropower is considered to be a renewable energy source.

One percent of sales must be from new renewables by

2003. This rises by 0.5 percent each year until 2009 and

then increases 1 percent per year thereafter until ended

by the Division of Energy Resources.149

Pennsylvania

In 1996, the average revenue per kilowatthour in Pennsylvania was 7.96 cents;150 in 1998, it was 7.86 cents. In

both years, Pennsylvania had the eleventh highest

average electricity price among the 50 States and the

District of Columbia. Like California and Massachusetts,

Pennsylvania falls into the camp of relatively highpriced States that have been somewhat aggressive in

pursuing restructuring.

In terms of numbers of customers that have switched

suppliers, Pennsylvania’s restructuring program is the

most successful in the Nation. Governor Tom Ridge

signed the Electricity Generation Customer Choice and

Competition Act into law on December 3, 1996. The law

basically separates the generation of electricity from the

services of transmitting and distributing it. The law

called for a phase-in of retail choice with one-third

eligible to choose by January 1998, another third by

January 1999, and the remaining third by January 2000.

Therefore, all customers in Pennsylvania can now choose
Energy Information Administration/The Changing Structure of the Electric Power Industry 2000: An Update 89

151 U.S. Department of Energy, Electric Utility Restructuring Weekly Update (February 18, 2000), http://www.eren.doe.gov/

electricity_restructuring/weekly/feb18_00.html. 152 Florida Public Service Commission, “States’ Electric Restructuring Activities Update,” http://www.psc.state.fl.us/general/

publications/restruc.htm. 153 “GreenMountain.com Makes Pitch for Clean Energy,” The Wall Street Journal (May 1, 2000), p. A36. 154 Ibid. 155 The Pennsylvania Electric Choice Program, http://www.electrichoice.com/public/pdf/elecchart.pdf. 156 The Energy Report (Arlington, VA: Financial Times Energy, May 8, 2000), p. 15. 157 Anne Millen Porter, “Why Pennsylvania Might Be the Only Game in Town,” Purchasing (July 16, 1998).

the generator of their electricity, but they are still

required to purchase the transmission and distribution

components of their electricity from the local supplier.

All utilities subject to the separation requirements were

required to file their restructuring plans with Pennsylvania’s Public Utilities Commission (PUC) in 1997. The

PUC has established industry groups to provide

recommendations on areas of concern that have arisen

in the restructuring process. These areas include education, information and billing, universal service, conservation, reliability, direct retail access implementation

scheduling, metering competitive safeguards, interaction

between suppliers and utilities, and taxes. A multimedia

consumer education campaign was launched by the

Pennsylvania Electric Choice Program to educate consumers about their ability to shop for a competitive

supplier. Included in the campaign were television and

radio advertisements as well as a four-page newspaper

insert.151

With regard to stranded costs, the PUC is authorized to

determine the level of stranded costs that each utility is

permitted to recover. Cost shifting between customers as

a result of stranded cost recovery is prohibited. The

costs can be recovered through a non-bypassable competitive transition charge (CTC) that will be reviewed

and adjusted annually for each customer who elects to

receive service from an alternative generation supplier.

The CTC will be collected by utilities over a maximum

period of 9 years, unless the PUC approves another time

frame. California, by contrast, authorized a collection

period of only 4 years.

The Competition Act encourages market participants to

coordinate their plans and transactions through an ISO

or functional equivalent. Electric utilities are permitted

to divest themselves of facilities or to reorganize their

corporate structures, but unbundling of services is

required. Additionally, public benefits programs are

funded by an energy surcharge to provide programs for

low-income assistance, energy conservation, and other

public purposes at the existing funding level.152

As a result of the new law encouraging outsiders to set

up business within the Commonwealth (unlike Florida

whose Supreme Court recently reaffirmed restrictions

on merchant plants), interesting developments have

occurred. For example, the largest wind farm in the

eastern United States is now in Pennsylvania. GreenMountain.com, which completed the eight-turbine

project in April 2000, is betting that customers will pay

a slight premium to switch to power that is cleaner than

the traditional source of Pennsylvania’s electricity&coal.153

Today, 52 suppliers are licensed to sell their generation

in the Commonwealth. A survey from the Office of

Consumer Advocate reports that 408,414 (8 percent) of

Pennsylvania’s residential electricity customers have

switched utility providers. The survey also noted that

95 percent of electricity customers are aware of their

options to switch to alternative suppliers under the law.

Of those who have switched, approximately 20 percent

have opted for a green power choice.154 In the PECO

service area in southeastern Pennsylvania, 15 percent of

residential customers, 30 percent of commercial customers, and 62 percent of industrial customers have

switched suppliers.155 Twenty-six percent of Duquesne

Light’s residential customers switched their supplier.

Technically, with the recent completion of Duquesne

Light’s sales of its generating assets to Orion Power

Holdings,156 all customers have a new supplier of electricity. The 26-percent citation represents those customers who actively sought an alternative supplier.

Duquesne Light provides service in the Greater Pittsburgh area.

One of the keys to Pennsylvania’s successful transition

to a competitive retail marketplace may have been its

pilot program. The program provided an incentive to

participate by guaranteeing a 10- to 13-percent discount

off the electric distribution company charge for all

classes of customers while establishing a generation

credit that allowed customers to obtain electricity supply

at 5 to 20 percent below the credit. “As a result, the pilot

was oversubscribed and the PUC and the electric

distribution companies had an opportunity to work out

problems in the transition to competition,” according to

Sandra Barber of the National Energy Team.157
90 Energy Information Administration/The Changing Structure of the Electric Power Industry 2000: An Update

158 Kentucky Association of Electric Cooperatives, Inc., http://www.kaec.org/stand/elecrestructuring.htm. 159 Energy Information Administration, “Status of Electricity Industry Restructuring by State,” http://www.eia.doe.gov/cneaf/

electricity/chg_str/tab5rev.html. 160 Energy Information Administration, Electric Power Annual 1999, Volume I, DOE/EIA-0348(99)/1 (Washington, DC, August 2000).

Kentucky 

In December 1999, Kentucky’s Special Task Force on

Electricity Restructuring released its findings and

recommendations. It found that “there is no compelling

reason at this time for Kentucky to move quickly to

restructure. Despite the prospects of Congressional

legislation to mandate restructuring, actions taken by 24

States and the District of Columbia to restructure, and

the fact that some of those States are geographically

contiguous to Kentucky, there are obvious advantages

for Kentucky adopting a wait-and-see approach to electricity restructuring. Representatives from other States

that have restructured as well as experts in the field of

electricity restructuring indicate that Kentucky is in a

unique position because of its existing low electricity

rates, which currently are the lowest east of the Rocky

Mountains. Most of Kentucky’s generation is coal-fired

and its generators are close to coal fields which are

among the cheapest fuel sources. Also, there has been

relatively little construction of generating capacity

recently, which has kept the Commonwealth’s collective

rate base low. A wait-and-see approach allows Kentucky

to monitor the progress of restructuring in other States

and to develop options that protect Kentucky’s existing

low rates for electricity.”158

In 1998, when the average revenue per kilowatthour in

Kentucky was 4.16 cents, only Idaho and Washington

had lower electricity rates. Unlike California, Massachusetts, and Pennsylvania, Kentucky has no compelling

price pressure to restructure. Therefore, the Commonwealth has no retail competition and no competitive

supplier activity. The only recent action of note was a

Public Service Commission Order in April 1999 to reduce rates for Kentucky Utilities and Louisville Gas and

Electric subsidiaries. The order calls for a $52 million

rate reduction under a performance-based rate making

approach.159

Because Kentucky has had no restructuring activity, no

stranded cost provisions are in place.

Issues Under Consideration

The current issues faced by the States are varied based

on the wide array of associated circumstances. Some

areas of concern, however, are similar across State lines,

for example:

 Remedying the loss of tax base for local authorities

 Generating renewable power and provisions for

net metering

 Evaluating performance-based ratemaking

 Providing non-discriminatory access to all electric

power suppliers

 Setting standards of conduct for suppliers and

utility affiliates

 Taking environmental issues into consideration

 Ensuring reliability in supplies and designation of

supplier of the last resort during transition

 Establishing consumer protection programs 

 Determining the role of public power utilities in

promoting competition.160

The following chapter examines in more detail the role

of recent mergers, acquisitions, and power plant divestitures of IOUs in restructuring the electric power

industry.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 91

161 Investor-owned utility acquisitions of foreign companies or non-energy related companies are not included in this analysis. 162 In some cases a holding company will also be a subsidiary of another holding company. The number of holding companies cited

in this report refers to the highest level holding company.

9. Mergers, Acquisitions, and Power Plant Divestitures

of Investor-Owned Electric Utilities

In response to increased competition in power generation, investor-owned utilities (IOUs) have engaged in a

wave of mergers and acquisitions during the past

decade, resulting in some very large IOUs. In contrast,

some IOUs have exited the power generation business

by selling their generation assets to an independent

power producer (IPP), or by transferring them to an

unregulated subsidiary within their company. The purpose of these contrasting strategies is to improve and

solidify a position in the new competitive industry. It is

too early to determine, however, the effectiveness of

these strategies on the industry and their benefits to

electricity customers. 

Recent mergers are classified broadly into two categories, each category representing a fundamentally

different reason for merging. The first category includes

mergers between IOUs or between IOUs and IPPs. These

mergers are motivated by the desire to increase power

generation capacity and/or transmission and distribution capacity and in general become a larger electric

utility. Most utility executives take the position that to

compete successfully in today’s electricity market a

company must be relatively large.

The second category includes mergers between electric

utilities and natural gas companies. Companies entering

into these types of mergers are seeking to become a

regional or even a national company that produces,

transports, and markets electricity and natural gas.

These are called convergence mergers because they

represent the increasing number of companies that own

both electricity and natural gas assets and are active in

both industries. Each of these categories of mergers is

described followed by an examination of recent

divestitures of power generation assets by IOUs.

Mergers and Acquisitions Between IOUs

and IPPs

From 1992 to April 2000, 35 mergers or acquisitions have

been completed between IOUs or between IOUs and

IPPs. Twelve mergers have been announced and are

now pending stockholder or Federal and State government approval (Table 14).161 The size of IOU mergers, in

terms of value of assets, is also increasing. Between 1992

and 1998, only four mergers were completed in which

the combined assets of the companies in each merger

were greater than $10 billion. More recently, eight mergers completed in 1999 or 2000, or pending completion,

each have combined assets greater than $10 billion. 

One of the effects of this wave of mergers is that there

are fewer operating electric utilities. In 1992, 172 operating utilities owned generation capacity in the United

States. By the end of 2000, the number of operating

utilities owning generation capacity will decrease to an

estimated 141 (Table 15). Power plant divestitures,

discussed later in the chapter, have also reduced the

total number of IOUs that own generation capacity. 

The majority of operating electric utilities are whollyowned subsidiaries of public utility holding companies.162 The effect of mergers on consolidation of the

industry is more evident when ownership capacity is

aggregated by holding companies. In 1992, there were 70

electric holding companies owning 78 percent of the

IOU-held generation capacity. By the end of 2000, the

number of electric holding companies will decrease to

53, and the generation capacity they own will increase to

about 86 percent of the total IOU-owned capacity,

primarily because of mergers and acquisitions. This

statistic suggests that relatively large companies are

becoming even larger.

Although many electric utilities see a need to grow

through mergers, others do not. Of 82 electric utilities

(53 electric utility holding companies and 29 independent electric utilities) in 2000 (Table 15), 56 (approximately 60 percent) have not been involved in a merger

since 1992 and have not announced plans to merge. This

suggests that even though the merger trend is strong,

most IOUs believe consolidation is not necessary to
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 92 Table 14. Mergers and Acquisitions Between Investor-Owned Electric Utilities or Between Investor-Owned Electric Ut

Independent Power Producers, 1992 Through April 2000 Merger Status Company 1 Company 2 Name of Surviving Company or Name of New Company States Served (Retail Customers) Combined Assets (Year-of-Merger Dollars 

Billions) 

Pending American Electric Power Co., Inc. (a registered holding company for AEP Generating Co., Appalachian Power Co., Columbus Southern Power, Indiana Michigan Power Co., Kentucky Power Co., Kingsport Power Co., Ohio Power Co., and Wheeling Power Co.) Central and South West Corp. (a registered holding company for Central Power and Light Co., Public Service Co. of Oklahoma, Southwestern Electric Power Co., and West Texas Utilities Co.) American Electric Power Co., Inc. (Central and South West will be a wholly-owned subsidiary) VA, WV OH, IN MI, KY TN, TX OK, LA AR AEP: $19.5 CSW: $13.7 Total: $33.2 

Consolidated Edison, Inc. (a holding company for Consolidated Edison Co. of New York, Inc., and Orange and Rockland Utilities) Northeast Utilities (a holding company for Connecticut Light & Power, Public Service Co. of New Hampshire, and Western Massachusetts Electric Co.) Consolidated Edison, Inc. (Northeast Utilities will be a subsidiary) NY, CT, MA, NH Consolidated Edison: $14.

Northeast: $10.4 Total: $24.8 

Carolina Power & Light Co. (an operating utility) Florida Progress Corp. (a holding company for Florida Power Corp.) Unknown FL, NC, SC CP&L: $8.3 Florida: $6.2 Total: $14.5 

UtiliCorp United (a holding company) St. Joseph Light & Power (an operating utility) Utilicorp (St. Joseph will keep its name and become a wholly- owned subsidiary) MO, KS CO, WV Utilicorp: $6.0 St. Joseph: $0.3 Total: $6.3 

New Century Energies (a registered holding company for Public Service Co. of Colorado, South- western Public Service Co., and Cheyenne Light, Fuel, & Power) Northern States Power (a holding company) Xcel Energy (unknown if New Centuries and Northern States Power operate as subsidiaries) NM, OK TX, WY AR, MI MN, SD ND, WI New Century: $7.7 NSP: $7.4 Total: $15.1 

UtiliCorp United (a holding company) Empire District Electric Co. (an operating utility) Unknown MO, CO KS, WV OK, AR Utilicorp: $6.3 Empire District: $0.7 Total: $7.0 Sierra Pacific Resources (a holding company for Sierra Pacific Power and Nevada Power) Portland General Electric (a subsidiary of ENRON Corp.) Sierra Pacific Resources (Portland General Electric will be a subsidiary) NV, CA, OR Sierra: $4.6 Portland: $3.2 Total: $7.8 Energy East (a holding company for New YorkElectric & Gas)

CMP Group(a holding company for Central Maine Power)

Energy East(CMP Group will bea wholly-ownedsubsidiary)

MA, MI

NY, NH

Energy East: $4.9CMP Group: $2.3Total: $7.2
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 93

Table 14. Mergers and Acquisitions Between Investor-Owned Electric Utilities or Between Investor-Owned Electric Ut

Independent Power Producers, 1992 Through April 2000 (Continued)

Merger

Status Company 1 Company 2

Name of Surviving

Company or Name

of New Company

States

Served

(Retail

Customers)

Combined Assets

(Year-of-Merger

Dollars in Billions) 

Pending

Unicom Corporation(a holding company for CommonwealthEdison)

PECO Energy Co.(a registered holdingcompany for SusquehannaPower Co.)

Exelon(A new holdingcompany)

IL, PA Unicom: $30.2

Peco: $12.0Total: $42.2

PowerGen plc(a foreign-owned power producer)

LG&E Energy Corp.(a holding company forLouisville Gas & Electric andKentucky Utilities)

PowerGen(LG&E will be awholly-ownedsubsidiary)

KY, VA Not available because

PowerGen is a foreigncompany. 

Cap Rock Energy Corporation(electric cooperative)

Citizens Utilities Company(an operating utility)

Cap Rock EnergyCorporation

AR, VT Not Applicable 

Kauai Island Electric Cooperative(an electric cooperative)

Citizens Utilities Company(an operating utility)

Kauai IslandElectric Cooperative

HI Not Applicable 

Completed in

2000

Berkshire Hathaway (et. al.)(an investor group)

MidAmerican EnergyHoldings Company(a holding company forMidAmerican Energy)

Berkshire Hathaway(MidAmerican will bea subsidiary)

IA, KS Unknown 

Laurel Hill Capital Partners, LLC(an investment company)

TNP Enterprises Inc. (a holding company forTexas-New Mexico PowerCompany)

TNP Enterprises willcontinue to exist

TX, NM Unknown 

National Grid Group PLC(a foreign company)

New England ElectricSystems (NEES)(a registered holdingcompany for Granite StateElectric Co., MassachusettsElectric Co., NarragansettElectric Co., and NewEngland Power Co.)

National Grid Group(NEES will be awholly-ownedsubsidiary)

VT, NH

MA

Not available becauseNational Grid Group is aforeign company.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 94 Table 14. Mergers and Acquisitions Between Investor-Owned Electric Utilities or Between Investor-Owned Electric Ut

Independent Power Producers, 1992 Through April 2000 (Continued) Merger Status Company 1 Company 2 Name of Surviving Company or Name of New Company States Served (Retail Customers) Combined Assets (Year-of-Merger Dollars 

Billions) 

Completed in 2000 (Continued) New England Electric System (a registered holding company for Granite State Electric Co., Massachusetts Electric Co., Narragansett Electric Co., and New England Power Co.) Eastern Utility Associates (a registered holding company for Blackstone Valley Electric Co., Newport Electric Corp., Eastern Edison Co., EUA, and Ocean State Corp.) New England Electric System (EUA will be a wholly- owned subsidiary) MA, RI VT, NH NEES: $5.3 EUA: $1.3 Total: $6.6 

Allegheny Energy, Inc. (a registered holding company) West Virginia Power (an operating utility) Allegheny Energy (West Virginia Power will be a subsidiary) PA, WV, OH, MD Allegheny: $6.7 West Virginia: $ .1 Total: $6.8 

Completed in 1999 Nevada Power (an operating utility) Sierra Pacific Resources (a holding company for Sierra Pacific Power Co.) Sierra Pacific Resources (Nevada Power will be a wholly-owned subsidiary) NV, CA Nevada Power: $2.6 Sierra Pacific: $2.0 Total: $4.6 

AES Corporation (an independent power producer) CILCORP (a holding company for Central Illinois Light Co.) AES (CILCORP will be a wholly-owned subsidiary) IL AES: $10.0 CILCORP: $1.3 Total: $11.3 

BCE Energy (a holding company for Boston Edison) Commonwealth Energy (a holding company for Cambridge Electric Light Co., Canal Electric Co., and Commonwealth Electric Co.) NSTAR (a new holding company; Boston Edison and Commonwealth Energy will be subsidiaries) MA BCE: $3.2 Commonwealth: $1.5 Total: $4.7 

Scottish Power PLC (a foreign company) PacifiCorp (an operating utility) Unknown (a new holding company; PacifiCorp will be a subsidiary) UT, OR, WY, WA, ID, MT, CA Not available because Scottish Power is a foreign company. 

CalEnergy Co., Inc. (an independent power producer) MidAmerican Energy Holding Co. (a holding company for MidAmerican Energy Co.) MidAmerican Energy Holding (CalEnergy will be a subsidiary) IA, KS CalEnergy: $7.5 MidAmerican: $4.3 Total: $11.8 

Consolidated Edison, Inc. (a holding company for Consolidated Edison Co. of New York, Inc.) Orange and Rockland Utilities (an operating utility) Consolidated Edison, Inc. (Orange and

Rockland will be awholly-ownedsubsidiary)

NY ConEd: $14.4

O&R: $1.3Total: $15.7
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 95

Table 14. Mergers and Acquisitions Between Investor-Owned Electric Utilities or Between Investor-Owned Electric Ut

Independent Power Producers, 1992 Through April 2000 (Continued)

Merger

Status Company 1 Company 2

Name of Surviving

Company or Name

of New Company

States

Served

(Retail

Customers)

Combined Assets

(Year-of-Merger

Dollars in Billions) 

Completed in

1998

Delmarva Power & Light Co.(an operating utility)

Atlantic Energy(a holding company forAtlantic City Electric Co.)

Conectiv(a new registeredholding company)

MD, DE

VA, NJ

Delmarva Power: $3.0Atlantic: $2.7Total: $5.7

LG&E Energy(a holding company for Louisville Gas &Electric Co.)

KU Energy(a holding company for Kentucky Utilities)

LG&E Energy(KU Energy will bedissolved)

KY, VA

TN

LG&E: $3.0KU Energy: $1.7Total: $4.7

WPL Holding, Inc.(a holding company for Wisconsin Power & Light)

IES Industries (a holding company for IESUtilities and InterstatePower, an operating utility)

Alliant Energy(a new holdingcompany)

WI, IA

MN, IL

WPL Holding: $1.9IES: $2.5Interstate: $0.6Total: $5.0

Wisconsin Energy(a holding company forWisconsin Electric Power Co.)

ESELCO(a holding company forEdison Sault Electric Co.)

Wisconsin EnergyCompany(ESELCO will be awholly-owned subsidiary)

WI, MI Wisconsin: $5.0

ESELCO: $0.1Total: $5.1

WPS Resources(a holding company for Wisconsin Public Service Corp.,Wisconsin River Power Co.)

Upper Peninsula Energy(a holding company forUpper Peninsula PowerCo.)

WPS Resources(Upper PeninsulaEnergy will cease to exist)

WI, MI WPS: $1.1

Upper Peninsula: $0.1Total: $1.2

Completed in

1997

Ohio Edison Co.(an operating utility; Ohio Edison alsoowns Pennsylvania Power Co.)

Centerior Energy(a holding company forCleveland ElectricIlluminating Co. and ToledoEdison Co.)

FirstEnergy(a new registeredholding company)

OH Ohio Edison: $8.9

Centerior: $10.2Total: $19.1

Public Service Co. of Colorado (an

operating utility and a holding company forCheyenne Light, Fuel, and Power)

Southwestern PublicService Co.(an operating utility)

New CenturyEnergies(a new registeredholding company)

CO, TX

NM, OK

KS

PS Co. of CO: $4.6Southwestern: $2.0Total: $6.6

Union Electric Co.(an operating utility)

CIPSCO (a holding company forCentral Illinois PublicService Co.)

Ameren(a new registeredholding company)

MO, IL Union: $6.8

CIPSCO: $1.8Total: $8.6

Pacific Gas & Electric Corp.(a holding company for Pacific Gas &Electric) 

U.S. Generating Co.(USGen)(an independent powerproducer)

Pacific Gas &Electric Corp.(USGen will be anunregulatedaffiliate of PG&E)

USGen

has plants in

numerous

States

USGen: $5.0 

Completed in

1996

New England Electric Systems(a registered holding company for GraniteState Electric Co., Massachusetts ElectricCo., Narragansett Electric Co., and NewEngland Power Co.)

Nantucket Electric(a small electric distributioncompany)

New EnglandElectric System(Nantucket Electric isa subsidiary)

VT, NH

MA

NEES: $5.1Nantucket: $0.1Total: $5.2
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 96 Table 14. Mergers and Acquisitions Between Investor-Owned Electric Utilities or Between Investor-Owned Electric Ut

Independent Power Producers, 1992 Through April 2000 (Continued) Merger Status Company 1 Company 2 Name of Surviving Company or Name of New Company States Served (Retail Customers) Combined Assets (Year-of-Merger Dollars in Billions) 

Completed in 1995 City of Groton, CT Bozrah Light and Power Unknown CT Unknown C

Delmarva Power and Light Conowingo Power Co. Delmarva Power and Light DE, MD, VA Delmarva Power: $2.9 Conowingo: $0.1 Total: $3.0 C

Midwest Resources (a holding company for Midwest Power Systems) Iowa-Illinois Gas and Electric (an operating utility) MidAmerican Energy (a holding company and operating utility) IA, SD, IL Midwest: $2.6 Iowa: $1.9 Total: $4.5 C

Completed in 1994 PSI Resources (an operating utility) Cincinnati Gas & Electric (an operating utility) CINergy (PSI Resources and Cincinnati are wholly- owned subsidiaries) IN, OH, KY PSI Resources: $2.9 Cincinnati: $5.2 Total: $8.1 C

Completed in 1993 Citizens Utilities Co. (an operating utility) Franklin Electric (an operating utility) Citizens Utilities (Franklin Electric ceased to exist) AZ, HI, VT Citizens: $2.6 Franklin: $0.8 Total: $3.4 C

IES Utilities Inc. (a holding company) Iowa Electric Light & Power and Iowa Southern Utilities IES Industries (IES Utilities, Iowa Electric, and Iowa Southern are subsidiaries) IA Total: $1.8 C

Texas Utilities (a holding company) Southwestern Electric Service Co. (an operating utility) Texas Utilities (Southwestern Electric is a subsidiary) TX Total: $20.9 C

Entergy Corp. (a holding company) Gulf States Utilities (a holding company) Entergy Corp. (Gulf States is a wholly-owned subsidiary) AR, TN, LA, TX, MS, NY Entergy: $14.2 Gulf States: $7.2 Total: $21.4 C

Completed in 1992 Connecticut Light & Power Fletcher Electric Light Co. Connecticut Light and Power CT Total: $6.2 C

Iowa Public Service Co. Iowa Power Co. Midwest Power IA, SD Total: $2.6 CKansas Power & Light Kansas Gas & Electric Western Resources KS Total: $5.2 CIndiana Michigan Power Co. Michigan Power Co. Indiana Michigan Power Co. IN, MI Total: $4.3 C

Unitil Corp. Fitchburg Gas & Electric Unitil Corp. NH Total: $0.2 CNortheast Utilities Public Service of New

Hampshire

Northeast Utilities NH, CT, MA Total: $10.6 C
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 97

163 Measures of concentration are sometimes used to identify the potential for a firm to exercise market power in a particular product

market. Measuring concentration is problematic in the electric power industry due to the difficulty in defining relevant markets. In this

report, measures of concentration were not developed for a particular electricity market. Instead, the term concentration is used broadly

to suggest that the recent wave of mergers is responsible for the increase in size of many IOUs. 164 For example, the CEO of New Century Energies, when discussing the merger between New Century Energies and Northern States

Power, said “The merger provides both the combined company and its operating units with the scale necessary to remain competitive in

a changing industry marketplace,” Press Release, New Century Energies (March 1999).

Table 15. Comparison of the Number of Investor-Owned Electric Utilities Owning Generation Capacity,

1992 and 2000

Company Category

1992 2000 (Estimated)

Number of

Operating

Utilities

Number of

Holding

Companies

Generation

Capacity

(Percent and

Thousand

Megawatts)

Number of

Operating

Utilities

Number of

Holding

Companies

Generation

Capacity

(Percent and

Thousand

Megawatts)

Utility that is a Subsidiary to a

Holding Company. . . . . . . . . . . . 113 70

(78%)

422.1 112 53

(86%)

384.5

Independent Utility . . . . . . . . . . . 59 --

(22%)

120.3 29 --

(14%)

60.6

 Total .................... 172 70

(100%)

542.4 141 53

(100%)

445.1

 a

The number of utilities reported here does not match the number of utilities reported in Chapter 2 for the following reasons: (1) these data include IOUs

that own power generation capacity, whereas the data reported in Chapter 2 include IOUs that operate power plants; (2) some utilities operate

transmission and distribution systems only and are not included here; and (3) these data exclude Alaska and Hawaii.

 Notes:  The 2000 data include the effects of pending mergers on consolidation of ownership. It is assumed that all pending mergers will be completed

by 2000.  Also, the 2000 data include the effects of generation asset divestitures on consolidation of ownership. It is assumed that all divestitures where

a buyer has been announced will be completed by 2000.  Holding companies were identified from the following documents: U.S. Securities and

Exchange Commission Financial and Corporate Reports, “Holding Companies Registered Under the Public Utility Holding Company Act of 1935 as of

October 1, 1995, as of December 1, 1996, and as of June 1, 1998,” and “Holding Companies Exempt from the Public Utility Holding Company Act of

1935 Under Section 3(a) (1) and 3(a) (2) Pursuant to Rule 2 Filings or By Order as of August 1, 1995 and as of November 1, 1997.”

 Sources: Energy Information Administration, Forms EIA-860, “Annual Electric Generator Report;” EIA-860A, “Annual Electric Generator Report %

Utility;” and EIA-861, “Annual Electric Utility Report.”

remain competitive in the industry in spite of the fact

that those companies choosing to merge are acquiring a

larger share of the industry’s assets.

The absolute number of companies provides insight into

consolidation trends, but concentration of generation

capacity ownership is perhaps more indicative of

consolidation.163 As a measure of consolidation of the

IOU sector, concentration indicates the extent to which

total capacity ownership is dispersed among companies.

The data suggest that generation capacity owned by

IOUs has been concentrated in the hands of a few

companies, and that mergers and acquisitions are

increasing the concentration of ownership within the

IOU sector. In 1992, the 10 largest utilities, ranked

according to generation capacity, owned 36 percent of

all IOU generation capacity; by the end of 2000 the 10

largest companies’ share will increase to an estimated 51

percent (Figure 29). Evidence of consolidation among the

20 largest companies is even more compelling. In 1992

the 20 largest companies owned 58 percent of total IOU

generation capacity; by the end of 2000 their share is

expected to increase to approximately 72 percent.

Mergers and acquisitions also cause consolidation of

ownership of the Nation’s transmission and distribution

systems. However, the outcome of this trend is unclear

because many utilities may transfer ownership of their

transmission system to regional transmission organizations in compliance with the Federal Energy Regulatory

Commission’s (FERC’s) Order 2000.

Reasons for Mergers and Acquisitions

Among Electric Utilities

Most, if not all, utility executives who have directed

their companies through mergers, argue that electric

utilities must be relatively large to be competitive.164 This

position underlies most of the mergers and acquisitions

recently completed between IOUs. Why does size
98 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

165 J. Anderson, “Making Operational Sense of Mergers and Acquisitions,” The Electricity Journal, Vol. 12, No. 7 (August/September

1999). 166 A convergence merger is defined as a merger in which one company’s primary business activity is electricity generation,

transmission, and/or sales and the other company’s primary business activity is natural gas production, processing, transportation, and/or

sales. 

1992 2000(Estimated)

0

20

40

60

80

100

Percent of Generation Capacity

Number of Companies

10 Largest 20 Largest

Figure 29. Concentration of Ownership of

Investor-Owned Utility Generating

Capacity, 1992 and 2000

matter? The thinking is that larger companies are able to

achieve economies of scale. By combining resources and

eliminating redundant or overlapping activities, larger

companies hope to benefit from increased efficiencies in

procurement, production, marketing, administration,

and other functional areas that smaller companies may

not be able to achieve. For example, a larger company,

because of a high volume of purchases, may be able to

negotiate a lower price from its fuel supplier than would

be available to a smaller company. Cost savings

resulting from increased efficiency can be passed to the

utility’s customers through lower electricity rates.

Whereas utility executives argue that a merger or acquisition will improve the efficiency of the combined

company, experience indicates that efficiency improvements are not guaranteed. One study reported that only

15 percent of mergers and acquisitions achieved their

expected financial objectives.165 Incomplete or underdeveloped plans to integrate the companies was noted

as a major factor for not achieving the objectives.

A company’s strategic objectives are also factors in the

decision to merge. Does the merger complement or

enhance the strategic objectives of the company is a

question asked by company executives in identifying

merger partners. Strategic objectives are company

specific and depend upon the merging companies’

particular circumstances. Building on core competencies,

securing more customers, consolidating transmission

and distribution facilities, diversifying power generating

capability, and acquiring additional managerial and

technical expertise are mentioned often as reasons. These

strategic reasons, however, relate to the desire to remain

competitive in the rapidly changing electricity industry.

Convergence Mergers

Increased competition has pressured electric utilities and

natural gas companies to combine operations in order to

become more efficient, to diversify products, to share

expertise and experience in energy markets, and to take

advantage of the growing use of natural-gas-fired power

plants. Combining electric utilities and natural gas companies is called convergence of the industries, and many

companies that once sold only electricity or natural gas

now sell both electricity and natural gas, or are involved

in other aspects of both industries. 

A combined electric and natural gas utility is not something new to the industry. Many IOUs sell both electricity and natural gas to retail customers. What is new

about the recent wave of mergers is that many of them

are between electric utilities and natural gas production,

processing, or interstate pipeline companies. These types

of mergers expand greatly the business opportunities for

electric utilities.

From 1997 through April 2000, 23 convergence mergers

involving companies with assets valued at $0.5 billion or

higher have been completed or are pending completion

(Table 16).166 No one knows for certain how long this

trend will continue, but many industry observers agree

that more convergence mergers will take place as

deregulation of the electric power industry continues

and electric and natural gas companies seek to diversify

their businesses.

Strategic Benefits of Convergence Mergers

The natural gas industry has a relatively complicated

structure that, depending on one’s classification scheme,

may consist of four major corporate segments (Table 17).

Notes: The 10 largest companies are public utility holding

companies that own one or more operating electric utilities.

The 2000 data assume that all pending mergers will be

completed by year-end 2000. Capacity owned by subsidiaries

of IOUs was not counted when computing rankings.

Sources: Energy Information Administration, Form EIA-860,

“Annual Electric Generator Report,” Form EIA-860A, “Annual

Electric Generator Report % Utility,” and Form EIA-861,

“Annual Electric Utility Report.”
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 99

Table 16. Selected Mergers and Acquisitions Involving Investor-Owned Electric Utilities and Natural Gas Companies,

1997 Through April 2000

Combined Electric Power and

Natural Gas Company

Companies Merging Type of 

Business

 Value of Assets

(Year-of-Merger

Dollars in Billions) Status Comm

Allegheny Energy, Inc.

Allegheny Energy(Allegheny Power)Mountaineer Gas

Electric/GasGas

Allegheny: $6.7Mountain Gas: $ 0.3Total: $7.0

Pending

Allegheny Energy is expanding its bcan cross-sell electricity and gas in 

DTE Energy

DTE Energy (Detroit Edison)MCN Energy Group (Michigan Consolidated GasCompany)

ElectricGas DTE Energy: $12.1 MCN Energy: $4.4

Total: $16.5 

Pending

This merger was announced in early holding company; it’s primary subsidinvestor-owned electric utility. MCN subsidiary Michigan Consolidated Gdistribution company. It also has gas marketing activities, and it has invescombined company will be the largeMichigan.

KeySpan Energy Corp.

KeySpan Energy Eastern Enterprises

Electric/GasGas

KeySpan: $6.9Eastern: $1.5Total: $8.4

Pending

KeySpan is a diversified energy comand natural gas in New York. This mgas customer base to New England

NISOURCE(a new holding company will beformed)

NISOURCE (Northern Indiana PublicService)Columbia Energy Group

Electric/GasGas

NISOURCE: $5.0Columbia: $7.0Total: $12.0

Pending

This merger was announced in Febintegrated energy company serving 

SCANA Corporation

SCANA Corp.(South Carolina Electric & Gas)Public Service Co. of NorthCarolina

Electric/GasGas

SCANA: $5.3PS of NC: $0.7Total: $6.0

Pending

SCANA is the parent company of SoPublic Service of North Carolina, Incexpands SCANA’s gas distribution bresources.

Vectren

SigCorp Inc. (Southern Indiana Gas &Electric)Indiana EnergyDPL (Natural Gas)

Electric/GasGasGas

SigCorp: $1.0Indiana Energy: $0.7DPL: $0.4Total: $2.1

Pending

SigCorp is a mid-size gas and electnatural gas distribution and energy mEnergy is purchasing DPL’s natural acquisitions increase the customer bcompany. 

Dominion Resources

Dominion Resources(Virginia Power)Consolidated Natural Gas

Electric/GasGas

Dominion: $17.5Consolidated: $6.4Total: $23.9

Completed 

in 2000

Dominion Resources is predominanregulated and unregulated power geNatural Gas is a large producer, tranmarketer of natural gas. This mergelargest integrated electric and natura

Dynegy Illinova Dynegy Electric/Gas Gas Illinova Corp: $6.4 Dynegy Inc: $5.3

Total: $11.7

Completed

in 2000

Illinova is an energy service companPower, an electric and natural gas uenergy products and services. It gremarketer to a full energy service ma
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 100Table 16. Selected Mergers and Acquisitions Involving Investor-Owned Electric Utilities and Natural Gas Companies, 1997 Through April 2000 (Continued) Combined Electric Power and Natural Gas Company Companies Merging Type of Business Value of Assets (Year-of-Merger Dollars in Billions) Status Comm

Energy East Corporation CTG Resources, Inc. (Connecticut Natural Gas Corp.) Gas Energy East: $4.9 Conn. Energy: $0.5 CTG Resources: $0.5 Total: $5.9 Completed in 2000 Connecticut Natural Gas is engaged 

and sale of natural gas in Hartford acentral Connecticut and in Greenwicthe third acquisition by Energy East strengthening its competitive positio

Energy East (New York State Electric & Gas) Connecticut Energy (Southern Connecticut Gas) Electric/Gas Gas Completed in 2000 Energy East, the parent company o

chosen to focus the company on enConnecticut Energy, the parent of Sdistribution company, increases Ene

Northeast region. Northeast Utilities Northeast Utilities Yankee Energy System Electric Gas Northeast: $2.2 Yankee Energy: $0.5 Total: $2.7 Completed in 2000 Northeast Utilities is one of New Eng

systems. Yankee Energy System, IYankee Gas Services Company, ondistribution companies in the Northe

Wisconsin Energy Wisconsin Energy Corp. Wicor (Washington Gas Co.) Electric/Gas Gas Wisconsin: $5.4 Wicor: $1.0 Total: $6.4 Completed in 2000 Wisconsin Energy is an electricity a

It owns two operating electric utilitieSault Electric. WICOR is a diversifietwo industries

&natural gas distributi

manufacturing. This merger strengt

business and helps to make it a majelectricity and natural gas markets. 

CMS Energy

CMS Energy (Consumer Energy)Panhandle Eastern Pipeline

Electric/GasGas

CMS Energy: $11.3Panhandle: $2.0Total: $13.3

Completed 

in 1999

CMS is a diversified energy compannatural gas operations. PanHandle iin the Midwest. Because PanHandledistribution and storage, this merger noted that gas-fueled electricity genMidwest, and this merger improves gas supply market.

Duke Energy Corporation Union Pacific Fuels Gas UP Fuels: $1.4 Completed in 1999

Duke Energy Field Services, a compCorporation, purchased the natural fractionation, and liquids pipeline bu(known as Union Pacific Fuels). ThiEnergy’s capability in the production areas in the natural gas business.

NIPSCO Industries

NIPSCO Industries (Northern Indiana PublicService)Bay State Gas

ElectricGas

NIPSCO: $3.7Bay State: $0.8Total: $4.5

Completed

in 1999

NIPSCO is a holding company for Nelectric and gas distribution utility. Butility. The merger expands NIPSC
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 101

Table 16. Selected Mergers and Acquisitions Involving Investor-Owned Electric Utilities and Natural Gas Companies,

1997 Through April 2000 (Continued)

Combined Electric Power and

Natural Gas Company Companies Merging

Type of 

Business

 Value of Assets

(Year-of-Merger

Dollars in Billions) Status Commen

KeySpan Energy

LILCO (Long Island Lighting Co.)Brooklyn Union Gas

Electric/GasGas

LILCO: $4.2Brooklyn Union: $2.3Total: $6.5

Completed

 in 1998

The merger of LILCO, an electric utgas utility, creates a regional energy serving primarily New York. 

Sempra Energy

ENOVA (San Diego Gas and Electric)Pacific Enterprises (Southern California Gas)

Electric/GasGas

ENOVA: $5.2Pacific: $5.0Total: $10.2

Completed 

in 1998

The merger of San Diego Gas & Eledistribution company, and Southern distribution company, creates one oenergy distribution companies in the 

Duke Energy Corporation Duke Power Company PanEnergy Corporation Electric Gas Duke Power: $13.5 PanEnergy: $8.6 Total: $22.1 Completed in 1997

In June 1997, Duke Power Co., one electric utilities, and PanEnergy Corpipeline and marketing company, coDuke Energy Corporation. Duke Enaggressive growth strategy, and its large diversified global energy comp

Enron

EnronPortland General Corp.(Portland General Electric)

GasElectric Enron: $23.4 Portland: $3.3

Total: $26.7

Completed

in 1997

The merger between Enron, an integcompany, and Portland General Elebetween a predominantly natural gautility. It marked the beginning of the industry and the creation of large elecompanies.

Pacific Gas & Electric Corporation

Pacific Gas & Electric Corp.Valero Energy Corp. (Valero Natural Gas Company)

Electric/GasGas PG&E Corp: $30.6 Valero: $1.5

Total: $32.1

Completed 

in 1997

PG&E Corporation is a large electric Valero is a natural gas process and storage company. This acquisition iin the Texas natural gas industry.

Puget Sound Energy Puget Sound Power & Light Co. Washington Energy Co. Electric Gas Puget Sound: $3.3 Washington: $1.0 Total: $4.3 Completed in 1997 This merger creates one of the large

natural gas utilities in the NorthwestPuget Sound Power & Light into the business. 

Reliant(formerly Houston Industries)

ReliantNorAm Energy

ElectricGas

Reliant: $12.3NorAm: $4.0Total: $16.3

Completed 

in 1997

Houston Industries is a holding comPower, a vertically integrated electrisubsidiary. NorAm Energy owns subengaging in wholesale electricity angas transmission, and retail natural 

TXU (formerly Texas Utilities Co.) Texas Utilities Co. ENSERCH (Lone Star Gas) Electric/Gas Gas Texas Utilities: $21.4 ENSERCH: $3.2 Total: $24.6 Completed in 1997

Texas Utilities is a combined electric It owns two electric utilities in Texasgas distribution and pipeline companCompany, the largest natural gas diTexas. This merger significantly exthe new combined company. 

 Note: Table includes mergers or acquisitions in which each company had assets valued at $0.5 billion or higher at the time of the merger.  Sources: Mergers and acquisitions were identified from trade journals, newspapers, and electric utility press releases found on Internet websites. Values of the 

obtained from the Securities and Exchange Commission 10-K filings.
102 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Natural Gas

Corporate Segments Description

Potential Strategic Benefits to Electric Company

of Combining with Natural Gas Company

Producers Perform gas exploration and production

functions. Generally market gas at the

wellhead to third parties who resell the

gas.

Electric company may have direct access to natural

gas to fuel power plants.

In general, by acquiring natural gas assets, the

combined company can offer a wider assortment of

energy products and services.

Pipelines Provide wholesale transportation/transmission function. Transport gas from

the field to market area. Pipeline

network facilities may include gathering,

transmission, compressor, storage, and

metering facilities.

Access to a reliable source of natural gas for existing

gas-fired power plants.

New gas-fired merchant power plants can be

strategically built relative to natural gas pipelines. 

In general, by acquiring natural gas assets, the

combined company can offer a wider assortment of

energy products and services.

Local Distribution

Companies

Provide retail sales and local

transportation deliveries.

Cross-sell natural gas to retail electricity customers

as a way to expand products and services.

Help reduce unit costs by expanding overhead over

larger customer base. 

Improve efficiencies of retail sales by combining

billing and other administrative functions.

Marketers and Brokers Engage in competitive wholesale gas

sales and services. Buy and resell

natural gas and gas management

services to others on a deregulated

basis.

Expand marketing effort and improve effectiveness of

marketing by selling both natural gas and electricity

to a common customer base. 

Apply gas company expertise and experience in gas

marketing to electricity marketing.

 Source: Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels.

Table 17. Overview of Strategic Benefits of a Combined Electric and Natural Gas Company

Some of the major natural gas companies are vertically

integrated, having exploration and production, pipelines, local distribution, and marketing components. The

majority of the companies are not vertically integrated

but specialize in one or two areas. Local distribution

companies (LDCs) are the largest segment of the

industry, with approximately 1,400 LDCs operating in

the United States. The benefits to an electric utility of a

convergence merger depend on where the gas company

is located in the production cycle. An analysis of the

current wave of convergence mergers shows that the

benefits of the merger generally fall into one or more of

the following areas.

Strengthen Wholesale Marketing and Trading Operations: Deregulation of the electricity and natural gas

industries has created spot markets for wholesale electricity and natural gas, as well as markets for buying,

selling, and trading financial instruments for risk management. In competitive commodity markets, prices for

the commodities (in this case, electricity or natural gas)

are sometimes volatile. Risk management, such as

buying futures contracts for electricity, helps reduce the

risk of price volatility. Many electric utilities and natural

gas companies realize that there are similar and related

techniques for electricity and natural gas marketing and

trading in spot markets, and are merging to form larger

organizations specializing in electricity and natural gas.

This provides the opportunity to sell a diversified line of

products to their customers, and it can help lower

administrative and processing costs. It also facilitates

arbitrage between electric power and natural gas prices.

One of the most frequently cited reasons for a convergence merger is the transferring of a gas company’s

experience in marketing and trading to an electric company that is relatively new in competitive markets and

commodity trading. The gas industry has been deregulated since the 1980s, and over that time surviving gas

companies have developed skills and experience in

working in competitive energy markets.

Diversify Products and Expand Retail Markets: Most

electric utilities believe that to remain competitive they

need to offer more products and services to their retail

customers. State-designed customer choice programs,
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 103

167 In general, stranded costs are historic financial obligations of utilities incurred in the regulated market that become unrecoverable

in a competitive market. Stranded costs are also known as stranded investments, stranded commitments, and transition costs.

2005 2010 2015 2020

Year

0

50

100

150

200

250

300

350

Gigawatts of Generation Capacity 

Renewable

Natural Gas

Coal

Figure 30. Cumulative Electricity Generation

Capacity Additions Through 2020

which allow retail customers to select their energy suppliers, motivate utilities to differentiate their products

from their competitors’ products. One strategy to

accomplish this is to merge with a local gas distribution

utility and offer both electricity and natural gas services

to customers. The idea of one-stop shopping appeals to

some customers, and combined marketing and delivery

systems can also help reduce the utility’s billing,

metering, and other administrative costs.

In addition to diversifying products and services, many

utilities see convergence mergers as a way to increase

market share, although this concept also applies to

mergers involving only electric utilities. Increased market share should lower per-customer costs by spreading

fixed costs over a larger customer base. Utility distribution systems have a large fixed-cost component. 

Another benefit from convergence mergers is the

potential for cross-selling electricity to natural gas

customers and natural gas to electricity customers. The

extent to which the customer base of the merging

companies does not overlap represents the potential for

increasing market share by cross-selling.

Expand and Strengthen Access to a Fuel Supply for

Merchant Power Plants: Electric utility holding companies are merging with natural gas companies that

specialize in natural gas production, processing, pipeline

operation, and storage. These are called upstream and

midstream functions in the natural gas industry

parlance. Distribution to the ultimate customer is a

downstream function. Electric utility mergers with upstream or midstream natural gas companies position the

new company to benefit from the growing demand for

natural gas stimulated by the projected growth in gasfired power plants across the country.

Because of the rising demand for electricity and the

retirement of older power generation units, 300 gigawatts of new generating capacity will be needed in the

United States by 2020 (Figure 30). Assuming an average

plant capacity of 300 megawatts, a projected 1,000 new

plants will be needed to meet electricity demand and to

offset plant retirements. Ninety percent of that capacity

is projected to be natural-gas-fired or dual-fired gas and

oil combined-cycle or combustion turbine technology.

These technologies have lower capital costs and operating and maintenance costs than other technologies,

and they more easily meet local and Federal Government emissions constraints, which are expected to

tighten in the future. Electric utilities that own upstream

and midstream natural gas resources will be positioned

to compete for customers in growing natural gas

markets brought on by the increase in demand for gasfired plants. Also, by owning upstream and midstream

gas resources, a company can expand its range of

products and services and build a marketing strategy

focused on a customer’s total energy needs. 

Regulatory Review of Electric Utility

Mergers and Acquisitions 

Electric utility mergers or acquisitions of substantial size

go through a review process involving a number of

Federal and State Government agencies (Table 18). At

the State level, the public utility commission or its

equivalent reviews the merger for potential anti-competitive effects and potential cost savings. States may

also review the merger’s effect on a utility’s stranded

costs,167 an issue brought on by industry deregulation.

Because most electric utility operations cross State

boundaries, it is not uncommon for multiple States to

review a merger. The extent and depth of the review can

vary widely between States, depending on the merger’s

expected impact in the State and the resources available

to conduct an evaluation.

Federal review of a proposed merger may involve up to

five different agencies. Either the Federal Trade Commission (FTC) or the Antitrust Division of the

Department of Justice (DOJ) could conduct a review to

 Source: Energy Information Administration, Annual Energy

Outlook 2000, DOE/EIA-0383 (2000) (Washington, DC,

December 1999).
104 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

168 M.W. Frankena and B.M. Owen, Electric Utility Mergers, Principles of Antitrust Analysis (Westport, CT: Praeger Publishers, 1994).

Government Agency Authority Type of Review

Department of Justice or Federal

Trade Commission

Section 7 of the Clayton Act, HartScott-Rodino Antitrust Improvements

Act

Examines mergers that may substantially

lessen competition or tend to create a

monopoly.

Federal Energy Regulatory

Commission

Federal Power Act of 1935,

Department of Energy Reorganization

Act of 1977, Energy Policy Act of 1992

Examines mergers and other combinations

to assure markets and access to reliable

service at reasonable prices.

Internal Revenue Service 16th Amendment to U.S. Constitution

(1913)

Determines amount of tax liability for

combination.

Nuclear Regulatory Commission Atomic Energy Act, Energy

Reorganization Act of 1974, Energy

Policy Act of 1992

Approves transfer of ownership of nuclear

facilities.

Securities and Exchange

Commission

Public Utility Holding Company Act of

1935 (PUHCA)

Assures compliance with PUHCA provisions

and protection of shareholder interest.

State Public Utility Commission,

State Attorney General Office

Various State Laws Full review may include antitrust, market

power, stranded costs, rates, and demandside management. The State has the

authority to allocate merger savings between

ratepayers and shareholders.

 Sources: Energy Information Administration, Natural Gas 1998: Issues and Trends, DOE/EIA-0560(98) (Washington, DC, June

1999), Chapter 7; and M.W. Frankena and B.M. Owen, Electric Utility Mergers, Principles of Antitrust Analysis (Westport, CT:

Praeger Publishers, 1994).

Table 18. Government Agencies Responsible for Reviewing Mergers and Acquisitions Involving

Electric Utilities

determine whether the merger is consistent with antitrust laws. Recently, the Antitrust Division of the DOJ,

rather than the FTC, has reviewed electric utility

mergers, but for most electric utility mergers the DOJ

relies on FERC to take the lead in evaluating the

competitive effects of the merger. The DOJ limits its role

to participation as an interested party.168 The Securities

and Exchange Commission (SEC) can become involved

in a merger or acquisition when a holding company

gains control of 10 percent or more of the voting

securities of another electric utility. If that is the case, the

SEC reviews the merger for compliance with requirements of the Public Utilities Holding Company Act of

1935. The Nuclear Regulatory Commission (NRC)

reviews a proposed merger or acquisition when it

involves the transfer of a nuclear power plant operating

license. 

Of all Federal Government agencies involved in

reviewing a proposed merger between electric utilities,

FERC’s review is probably the most extensive, covering

the merger’s potential effects on competition in the

industry, electricity rates to customers, and regulation.

FERC sometimes will request merger applicants to

prepare special reports showing the merger’s effect on

market power or the cost savings and efficiencies that

are expected from the merger. These reports and other

documents, such as public comments about the merger,

are available on the Commission’s website

(www.ferc.fed.us). Depending on the level of public

interest, the size of the merging companies, and the

merger’s potential impact on the industry, FERC may

hold public hearings to obtain information and to

discuss important issues associated with the merger.

Divestiture of Power Generation Assets 

The previous sections discussed mergers and acquisitions and their effects on the structure of the industry.

Recent divestitures of power generation assets (i.e.,

power plants) by a number of IOUs is another type of

corporate realignment that is changing the structure of

the industry. Divestiture of generation assets is defined

as the sale of assets to another company, or the transfer
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 105

Table 19. Status of Power Generation Asset Divestitures by Investor-Owned Electric Utilities,

as of April 2000

Status Category

Capacity

(GW) Percent of Total

Percent of Total U.S.

Generation Capacity

Sold ................................ 58.0 37 8

Pending Sale (Buyer Announced) ......... 28.2 18 4

For Sale (No Buyer Announced) .......... 31.9 20 4

Transferred to Unregulated Subsidiarya . . . . . 4.1 3 1

Pending Transfer to Unregulated Subsidiary . 34.2 22 5

Total ............................... 156.5 100 22

 aIncludes generation capacity owned by a holding company that is being transferred from its electric utility subsidiary to its

nonutility subsidiary.

 Note: Totals may not equal sum of individual components because of independent rounding.

 Source: Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels. Compiled from information

in trade journals, newspapers, and Internet websites, 1998 through September 1999.

of assets from the regulated utility subsidiary to an

unregulated subsidiary within the company structure.

Over the past 3 years, IOUs have divested power

generation assets at unprecedented levels. From late

1997 through April 2000, 51 IOUs (32 percent of the 161

IOUs owning generation capacity) have divested or are

in the process of divesting 156.5 gigawatts of power

generation capacity, representing approximately 22

percent of total U.S. electric utility generation capacity

(Table 19). Of the 156.5 gigawatts, 86.2 gigawatts have

been sold or are pending completion of the sale, 31.9

gigawatts are up for sale, and 38.3 gigawatts will be

transferred by an IOU to its nonutility subsidiary. Some

industry observers have estimated that ownership may

change for up to 50 percent of total U.S. generation

capacity (about 364 gigawatts as of 1998) over the next

10 years. No one can predict with certainty the volume

of future divestitures, but more are expected as

restructuring of the electric power industry proceeds.

The idea of an electric utility divesting generation assets

can be traced back to before November 1996, when

FERC issued Order 888 requiring electric utilities to

allow access to their transmission lines to other

electricity suppliers. As discussed in Chapter 7, FERC

believed that access to transmission lines was necessary

in order for a competitive power generation market to

develop. Some industry participants believed, however,

that open access to the transmission system would not

be sufficient. When transmission line capacity becomes

limited due to high usage, it is argued that utilities that

own the transmission lines will favor power from their

own generators over a competitor’s generator. Many

thought the answer to this problem was for FERC to

require utilities that own both power generators and

transmission lines to divest their power generation

assets.

In Order 888, FERC took a less intrusive alternative to

actual divestiture of generation assets by requiring functional unbundling. Functional unbundling is achieved

when a company’s organizational structure separates

operation of and access to the transmission system from

power generation. To comply with functional unbundling, electric utilities created an open access transmission tariff, established separate rates for wholesale

generation, transmission, and ancillary services, and

established an electronic information network that

supplies information on the availability of transmission

capacity to customers. All IOUs have complied with

FERC’s functional unbundling requirements and in some

regions electric utilities have formed independent

system operator (ISO) companies and turned control

(but not ownership) of their transmission assets over to

the ISOs. This action can be construed as a way of

unbundling power generation from transmission.

Why Investor-Owned Electric Utilities Are

Divesting Power Generation Assets

Even though all IOUs have functionally unbundled

generation from transmission, and some have formed

ISOs, many utilities have divested their power plants

because of State requirements or as a result of strategic

business decisions made by the utility. With regard to

State requirements, States that are opening the electric

market to retail competition view the separation of

power generation ownership from power transmission

and distribution ownership as a prerequisite for retail
106 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

competition. Some States have passed laws requiring

utilities to divest their power plants. California, Connecticut, Maine, New Hampshire, and Rhode Island are

examples of States with laws explicitly requiring utilities

to divest their fossil and hydroelectric generation assets

and, potentially, any ownership in nuclear power

generating assets.

In other States that have passed electricity industry

restructuring legislation, the requirements for unbundling are not always clear and vary from State to

State. In some instances, the State public utility commission (PUC) may encourage divestiture to arrive at a

quantifiable level of stranded costs for purposes of

recovery during the transition to competition. On the

other hand, many times the PUCs are not explicit in their

unbundling requirements, leaving it to the utility to

propose a method that satisfies the PUC’s unbundling

objectives and satisfies the strategic and economic

objectives of the utility. The utility prepares a company

restructuring plan which may include selling its assets

or, alternatively, transferring its assets to an unregulated

subsidiary company. Negotiation and compromise

between the PUC and the utility are part of the process

of finalizing the plan. Not all States that have restructured their electricity industry require resident electric

utilities to unbundle their assets. 

As a business strategy, a few utilities have decided to

sell their power plants, indicating that they cannot

compete in a competitive power market. For example,

General Public Utilities, serving customers in New

Jersey and Pennsylvania, sold its fossil-fueled and

hydroelectric generating assets, and will focus on

running its transmission and distribution systems in a

regulated environment. Potomac Electric Power Company, serving primarily Maryland and Washington, DC,

announced in February 1999 that it will sell its generation business and concentrate on distribution. Both of

these companies concluded that at their present level of

power generation capacity, they are too small to compete effectively in a competitive power market. It is

expected that more small electric utilities will either

merge with other utilities or sell their power generation

assets.

In a few instances, an IOU will divest power generation

capacity to mitigate potential market power resulting

from a merger. For example, American Electric Power

Company and Central and South West Corporation have

agreed, as a condition for obtaining approval of their

pending merger, to divest 1,604 megawatts of generation

capacity in Texas.

Five Census Divisions Accounting for Most

Generation Asset Divestitures

Five census divisions&Middle Atlantic, New England,

South Atlantic, East North Central, and Pacific Contiguous&account for a total of 141.3 gigawatts of the

divested capacity, representing 90 percent of the 156.5

gigawatts of actual and planned divestitures in the

United States as of early April 2000 (Figure 31). The

majority of divestitures are concentrated in these regions

because the States in these regions were among the first

in the Nation to promote retail competition. With the

exception of States in the South Atlantic Division, most

of the States in the other four divisions passed legislation

in 1996 or 1997 restructuring the electricity industry, and

they have had over 2 years to implement their restructuring programs.

IOUs in New England have completed divesting their

power plants; approximately 25.2 gigawatts have been

sold, representing all of the region’s generating capacity.

Capacity in the region that has not been divested is

owned by IPPs or municipal or Federal Government

power plants. IOUs in the Middle Atlantic region,

mainly in New York and Pennsylvania, have divested or

are in the process of divesting more than 33 gigawatts,

accounting for approximately 43 percent of the region’s

generating capacity. IOUs in California have divested

slightly over 28 gigawatts, representing about 36 percent

of the generating capacity in the Pacific Contiguous

region. 

Selling Generation Assets and the Approval

Process

How power plants are sold is important to the owner

and potential buyers. The procedure should ensure

fairness to all interested buyers and ensure that the

utility gets a fair market value. The most popular divestiture method is the auction. The advantages of auctions

are that they have been used successfully for many years

to sell products, they can be easily understood and

monitored, and they can produce greater revenues than

other methods, if designed properly. 

Many of the IOUs divesting assets have used a twostage auction process. In the first stage, the utility

advertises the sale of the plant and bidders submit

notifications of interest back to the utility. Advertising

the sale of the plant can be accomplished in many ways.

One way is to develop a potential buyers list and send

each a notification that a power plant is for sale. In the
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 107

3DFLILF

1RQFRQWLJXRXV

 *:

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H I

Figure 31. Investor-Owned Electric Utility Generation Capacity Divested or to be Divested by Census

Division, as of April 2000

second stage, the utility selects a shortlist of buyers.

Short-listed bidders conduct due diligence and submit

their final bids. Sometimes post-bid negotiations are

conducted, but they have the tendency to reduce the bid

price because the bidder, knowing that negotiations will

be conducted, can change the original bid price.

When the divestiture involves many plants, packaging

of the plants is important. Packaging refers to the group

of assets that will be sold at one auction. In many cases,

bidders cannot submit a bid for just some of the assets,

but must bid on all the assets in the package. Thus, it is

important to combine assets in a way that will interest

potential buyers.

All power plant sales must be approved by the PUC of

the affected States. The PUC examines the sale’s impact

on the utility’s customers, the environment, and other

public interests, and resolves any conflicts which arise.

Ideally, contentious issues are resolved during the

planning stage.

With the exception of hydroelectric power plants, the

Federal Government has only a small role in IOU asset

divestitures. FERC’s position is that generation assets

are not under its jurisdiction and its approval is not

required unless the sale includes transmission assets

along with generation assets.

Conclusions About Mergers, Acquisitions,

and Divestitures of Generation Assets

Deregulation of the electric power industry and the

ensuing competition is driving IOUs to formulate

strategies that will help them to compete in the changing

industry. Many times the strategy is a merger or

acquisition. Recent mergers have created large vertically

integrated regional electric utilities, and more are

 Note: Nationally, approximately 22 percent of total power generation capacity has been divested or will be divested.

 Source: Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels. Compiled from information

in trade journals, newspapers, and Internet websites, 1998 through April 2000.
108 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

expected as some of the pending mergers are completed.

One effect of these mergers is that ownership of IOU

power generation capacity is becoming more concentrated. By the end of 2000, it is expected that the 20

largest IOUs will own about 72 percent of total IOU

capacity (Figure 29). 

Over the past few years, IOUs have increasingly merged

with natural gas production and gas pipeline companies,

creating vertically integrated energy companies. These

mergers are motivated primarily by the growth in gasfired power plants and the opportunity to become a

major fuel supplier to these power plants. Combined

electricity and natural gas marketing and diversification

of products and services are also reasons for these

mergers.

Induced by State government restructuring of the electric industry and the emergence of retail competition,

many IOUs have divested their power generation assets

and will focus on operating their transmission and distribution business. From 1998 through April 2000, IOUs

have either divested or are in the process of divesting

approximately 156.5 gigawatts of power generation

capacity. Over 95 percent of this capacity has been or

will be acquired by IPPs, furthering the growth of the

IPP segment of the industry.

Since the early 1990s, when deregulation and restructuring of the industry began, mergers and acquisitions

in the industry have accelerated. The intent of these

corporate realignments is to strengthen the company’s

position in the competitive industry. It is not clear,

however, if these strategies will benefit most companies,

and if the industry and electric customers will be better

off as well.
Appendix A

History of the U.S.

Electric Power 

Industry, 1882-1991
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 111

169The following is a historical sketch of the electric power industry from 1882 through 1991. The information for utilities from 1882

to 1984 is excerpted from Energy Information Administration (EIA), Annual Outlook for U.S. Electric Power 1985, DOE/EIA-0474(85)

(Washington, DC, August 1985). Utility and nonutility information from 1985 to 1991 is excerpted from EIA, The Changing Structure of the

U.S. Electric Power Industry 1970-1991, DOE/EIA-0562 (Washington, DC, March 1993). 170C. E. Neil, “Entering the Seventh Decade of Electric Power, Some Highlights in the History of Electrical Development,” reprinted

from Edison Electric Institute Bulletin (September 1942), p. 6. 171A.J. Foster, The Coming of the Electrical Age to the United States (New York, NY: Arno Press, 1979), pp. 120, 123, 181. 172Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970 (New York, NY: 1973), p. 24. 173C.E. Neil, “Entering the Seventh Decade of Electric Power,” from Edison Electric Institute Bulletin (September 1942), p. 6.

Appendix A

History of the U.S. Electric Power Industry, 1882-1991169

Beginnings: 1882-1900

The modern electric utility industry began in the 1880s.

It evolved from gas and electric carbon-arc commercial

and street lighting systems. Thomas Edison's Pearl Street

electricity generating station, which opened September

4, 1882, in New York City, introduced the industry by

featuring the four key elements of a modern electric

utility system. It featured reliable central generation,

efficient distribution, a successful end use (in 1882, the

light bulb), and a competitive price. A model of efficiency for its time, Pearl Street used one-third the fuel of

its predecessors, burning about 10 pounds of coal per

kilowatthour, a “heat rate” equivalent of about 138,000

Btu per kilowatthour.170 Initially the Pearl Street utility

served 59 customers for about 24 cents per kilowatthour.171 In the late 1880s, power demand for electric

motors brought the industry from mainly nighttime

lighting to 24-hour service and dramatically raised

electricity demand for transportation and industry

needs. By the end of the 1880s, small central stations

dotted many U.S. cities; each was limited to a few blocks

area because of transmission inefficiencies of direct

current (dc).

The hydroelectric development of Niagara Falls by

George Westinghouse in 1896 inaugurated the practice

of placing generating stations far from consumption

centers. The Niagara plant transmitted massive amounts

of power to Buffalo, New York, over 20 miles away.

With Niagara, Westinghouse convincingly demonstrated

both the general superiority of transmitting power with

electricity rather than by mechanical means (the use of

ropes, hydraulic pipes, or compressed air had also been

proposed) and the transmission superiority at that time

of alternating current (ac) over direct current (dc). Niagara set a contemporary standard for generator size, and

was the first large system supplying electricity from one

circuit for multiple end-uses (railway, lighting, power).

Electric utilities spread rapidly in the 1890s. Municipally

owned utilities predominantly supplied street lighting

and trolley services and reached their peak share of total

generation, about 8 percent, at the turn of the century.172

Privately owned multiservice utilities controlled the rest

of the industry, aggressively competing for central city

markets. Competition and technological improvements

served to lower electricity prices steadily, with nominal

residential prices falling to less than 17 cents per

kilowatthour by the beginning of the 20th century.

Era of Private Utilities: 1901-1932

From 1901 through 1932, growing economies of scale

hastened growth and consolidation in the electric utility

industry, as well as the beginnings of State and Federal

regulation. Larger, more efficient steam turbine-powered generators quickly replaced reciprocating steam

engines; average heat rates dropped from 92,500 Btu per

kilowatthour in 1902 to 20,700 Btu per kilowatthour by

1932.173 As a direct consequence of those growing

efficiencies, small private and municipal lighting and

railway or power companies either merged with,

purchased electricity from, or were absorbed quickly by

ever-larger, more efficient private multiservice systems.

Systems and cities interconnected with high voltage

transmission lines. Private electric utility ownership also
112 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

174Encyclopedia Americana, International Edition, Vol. 22 (New York, NY: Americana Corporation, 1977), p. 769. 175Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970 (New York, NY: 1973), p. 24. 176U.S. Bureau of the Census, Historical Statistics of the United States, Colonial Times to 1970, Bicentennial Edition, Part 2 (Washington, DC,

1975), p. 827.

consolidated into large utility holding companies, each

“holding” controlling interest in a number of electric

utilities. At their peak in the late 1920s, the 16 largest

electric power holding companies controlled more than

75 percent of all U.S. generation.174

The growth of utility service areas, first beyond city

boundaries and then across State lines, brought State

regulation of electric utilities in the early 1900s to ensure

that the monopolistic utilities did not take advantage of

their customers. Georgia, New York, and Wisconsin

established State public service commissions in 1907,

followed quickly by more than 20 other States. Basic

State powers included the authority to franchise the

utilities, to regulate their rates, financing, and service,

and to establish utility accounting systems.

The foundations for strong Federal involvement in the

electricity industry were established between 1901 and

1932, based on three factors: first, the electric power

industry became recognized as a natural monopoly in

interstate commerce (producing a product most efficiently provided by one supplier) subject to Federal

regulation; second, the Federal Government owned most

of the Nation's hydroelectric resources; and third,

Federal economic development programs accelerated,

including electricity generation. In 1906, Congress

authorized the sale of surplus Federal power from

western irrigation projects, giving sale preference to

municipalities. The Federal Water Power Act of 1920

(P.L. 66-280) codified Federal powers and established

the Federal Power Commission (FPC) to issue hydroelectric development licenses revokable after 50 years. In

1928, Congress authorized the Boulder Canyon Project

for irrigation, flood control, and electricity production.

From 1901 to 1932, electric utility capacity and generation grew at annual average rates of about 12 percent a

year, despite a 14-percent absolute drop in generation

from 1929 to the Depression-era low in 1932. Both the

number of municipal utilities and their share of total

generation dropped steadily, as municipals were

overwhelmed by larger, more efficient private systems.

By 1932 municipals contributed only 5 percent of total

generation. At the same time, State-owned utilities and

Federal systems, however, grew noticeably, together

contributing more than 1 percent of total generation.

Private utilities provided the remaining 94 percent.175

Electricity prices dropped, with nominal residential

electricity prices falling to 5.6 cents per kilowatthour in

1932, a level about one-third their price at the beginning

of the century. In 1907, only 8 percent of all dwellings

were using electricity; by 1932, this figure had risen to 67

percent. By 1932 considerably more than 80 percent of

urban dwellings were electrified, while only 11 percent

of farm dwellings had electrical service. This disparity

between urban and rural service led to demands by farm

interests for government help in obtaining electric

power.176

Emergence of Federal Power:

1933-1950

The Federal Government became a regulator of private

utilities in the 1930s; it also became a major producer of

electricity beginning in this period. The 1933-1950 period

was also characterized by continued growth of the

industry, increased consolidation and interconnection,

and increasing economies of scale. 

1933-1941

The Federal Government moved quickly in the

mid-1930s to regulate private power and, where opportunities appeared, to produce and distribute less

expensive Federally produced electricity to preference

customers. Federal participation was hastened by

widespread public perception of private utility abuses

and national efforts to overcome the Depression.

First, the Federal Government moved to regulate private

utilities. To counter utility abuses beyond State control,

the Public Utility Holding Company Act of 1935

(PUHCA, P.L. 74-333) provided for the regulation of

utility holding companies by the Securities and Exchange Commission (SEC). The Federal Power Act of

1935 (Title II of PUHCA) established FPC regulation of

utilities involved in interstate wholesale transmission

and sale of electric power.

Second, the Federal Government encouraged the growth

of rural electricity service by subsidizing the formation

of rural electric cooperatives. The Rural Electrification

Act of 1936 (P.L. 74-605) established the Rural Electrification Administration (REA) to provide loans and

assistance to organizations providing electricity to rural
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 113

177Ibid. 178Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970 (New York, NY: 1973), pp. 2, 24. 179C.E. Neil, “Entering the Seventh Decade of Electric Power,” from Edison Electric Institute Bulletin (September 1942), p. 6. 180Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970 (New York, NY: 1973), p. 24. 181Edison Electric Institute, EEI Pocketbook of Electric Utility Industry Statistics (New York, NY: 1983), p. 21. 182Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970 (New York, NY: 1973), p. 24.

areas and towns with populations under 2,500.

REA-backed cooperatives enjoyed Federal power

preferences plus lower property assessments, exemptions from Federal and State income taxes, and

exemption from State and FPC regulation. As a result,

by 1941 the proportion of farm homes electrified rose to

35 percent, more than three times that of 1932.177

Third, in the 1930s Federal electricity generation

expanded, providing less expensive electricity to

municipals and cooperatives. Large Bureau of Reclamation dams began serving the western States; Hoover

Dam began generation in 1936, followed by other large

projects. Grand Coulee, the Nation's largest hydroelectric dam, began operation in 1941. U.S. Army Corps

of Engineers flood control dams provided additional

low-priced power for preference customers. Under the

Tennessee Valley Authority Act of 1933 (P.L. 73-17), the

Federal Government supplied electric power to States,

counties, municipalities, and nonprofit cooperatives,

soon including those of the REA. The Bonneville Project

Act of 1937 (P.L. 75-329) pioneered the Federal power

marketing administrations. By 1940, Federal power

pricing policy was set; all Federal power was marketed

at the lowest possible price while still covering costs.

From 1933 to 1941, half of all new capacity was provided

by Federal and other public power installations. By the

end of 1941, public power contributed 12 percent of total

utility generation, with Federal power alone contributing

almost 7 percent.178

During the pre-World War II years, electricity generating systems continued to grow in size and efficiency.

Maximum turbine sizes and pressures doubled, and

steam temperatures increased; generator cooling by

pressurized hydrogen was introduced, resulting in

higher generator outputs. Average heat rates dropped to

18,600 Btu per kilowatthour by 1941.179 Improvements in

transformers, circuit breakers, protection and reclosing

devices, and transmission and distribution systems also

continued, increasing both the efficiency and the

reliability of electric utility systems.

Electricity prices continued to decline. Nominal

residential electricity prices fell to 3.73 cents per kilowatthour in 1941, a drop of about one-third from 1932.

Demand for electric power grew steadily from 1932

to 1941, with generation growth averaging over 8

percent a year, although capacity increased less than 2.5

percent per year.

1942-1950

Soaring electricity demand during World War II was

met by increased use of privately owned capacity and a

dramatic growth in Federal power. From 1941 to 1945,

Federal capacity growth averaged 21 percent a year, and

generation grew by 27 percent. By the war's end, Federal

electricity generation had grown to more than 12.5

percent of U.S. generation.180 Total U.S. generation grew

at an annual average rate of over 7.5 percent during

these war years, with capacity increasing at an annual

average rate of almost 4.5 percent.

Both residential and commercial end use of electricity

grew rapidly from 1941 to 1945, despite the war. Almost

one-half of all farm dwellings were electrified by 1945.

Growth in demand was helped by continuing technological improvements, yielding overall heat rates

below 16,000 Btu per kilowatthour181 and residential

electricity price drops averaging over 2 percent a year.

Public and Federal power continued to grow, and terms

of public sale improved. Generating capacity built for

defense was directed to public sale. The 1944 Pace Act

(Department of Agriculture Organic Act, P.L. 78-425)

extended REA indefinitely, dropped REA long-term

interest rates below market rates, and authorized

additional dam construction. The Flood Control Act of

1944 (P.L. 78-534) gave the Secretary of Interior

jurisdiction over U.S. Army Corps of Engineers' electric

power sales and extended public preference to all Corps

power. The Southwestern Power Administration

(SWPA) and the Southeastern Power Administration

(SEPA) were established in 1943 and 1950, respectively,

to market Federal power to preference customers. The

First Deficiency Appropriation Act of 1949 (P.L. 81-71)

in effect authorized TVA construction of thermal-electric

power plants for commercial electricity sale. By 1950,

Federal generation contributed over 12 percent of total

U.S. generation, while cooperatives and other public

power provided almost 7 percent.182 In settling the Hope

Natural Gas case (Federal Power Commission vs. Hope

Natural Gas Company, 1944), the Supreme Court closed
114 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

183U.S. Bureau of the Census, Historical Statistics of the United States (Washington, DC, 1972), pp. 827-828. 184Derived from Edison Electric Institute, EEI Pocketbook of Electric Utility Industry Statistics (New York, NY: 1983), p. 21. 185Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970 (New York, NY: 1973), p. 23. 186Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970 (New York, NY: 1973), p. 24. 187Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970 (New York, NY: 1973), p. 24. 188Energy Information Administration, Annual Energy Review 1984, DOE/EIA-0384(84) (Washington, DC, April 1985), p. 187.

a longstanding dispute by allowing either original or

replacement cost accounting in utility rate-making, so

long as just and reasonable rates result.

Following a brief decline at war's end in 1945, overall

demand for electricity continued to grow. From 1945

through 1950, generation growth averaged more than

8 percent a year and capacity over 6.5 percent. Residential electricity consumption grew most rapidly,

almost 14 percent a year, and the share of farms

electrified rose to almost 80 percent.183 Growth was

encouraged by continued efficiency improvements; by

1950 heat rates had fallen below 15,000 Btu per

kilowatthour.184 Drops in nominal residential electricity

prices averaged 3 percent a year.

Utility Prosperity: 1951-1970

The era following the end of World War II through 1970

marked a time of essentially uninterrupted prosperity

for the electric utility industry. Demand for electricity

grew rapidly, consistently, and predictably, while electricity prices continued to fall. The arrival of commercial

nuclear power held the promise of an even more

prosperous future. At the same time, problems that were

later to affect the industry dramatically either did not

exist or were not yet serious.

The 1950s

Three major characteristics marked the electric utility

industry in the 1950s: robust growth, the introduction of

commercial nuclear power, and other public power

expansion replacing Federal power growth.

From 1950 to 1960, generation grew by an average of

over 8.5 percent a year, led by strong increases in

residential electricity demand and near completion of

rural electrification. Capacity grew slightly more rapidly

than generation, averaging almost 9.5 percent annually.

With generating efficiencies still improving, electricity

prices continued to decline, as evidenced by drops in

nominal residential electricity prices averaging about

1 percent a year.185

Commercial nuclear power was introduced in the 1950s.

The Atomic Energy Act of 1954 (P.L. 83-703) allowed

private development of commercial nuclear power, and

the Price-Anderson Act (P.L. 85-256) reduced private

liability by guaranteeing public compensation in the

event of a commercial nuclear catastrophe. The Nation's

first central station commercial nuclear reactor, located

in Shippingport, Pennsylvania, began operation in 1957.

Finally, during the 1950s new Federal power plant

construction slowed, but the slowdown was offset by

more rapid growth of other public power capacity. Both

the “no new starts” policy of the Eisenhower Administration and a lack of additional major hydroelectric sites

checked major new Federal development. Nevertheless,

projects begun earlier continued to come on line, and

Federal generation reached its highest share of total

generation, more than 17 percent, in 1957. TVA added

thermal capacity, by 1960 becoming predominantly a

thermal rather than hydroelectric system. Non-Federal

public power grew rapidly in the 1950s, led by cooperatives, power districts, and State projects. Generation

from non-Federal public power plants and cooperatives

increased from more than 6.5 percent of total generation

in 1950 to almost 8.5 percent in 1960.186

The 1960s

During the 1960s high electricity growth rates continued,

paralleled by growth in nuclear power generation.

During the period, however, signs of future difficulties

in the electric power industry appeared, including

decreasing efficiency gains, escalating costs, and environmental concerns.

Vigorous growth continued throughout the 1960s,

prompted by overall economic growth, declining real

energy prices, and growing consumer preference for

electricity because of its convenience, versatility, and

price. Generation and capacity growth averaged almost

7.5 percent a year, predominantly from increases in

petroleum- and gas-fired generation. Cooperatives accelerated capacity additions, and by 1970 non-Federal

public power contributed well over 10 percent of total

utility generation.187 Demand grew nearly 7.5 percent a

year, helped by annual declines of over 1.5 percent in

residential and commercial electricity prices.188
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 115

189Energy Information Administration, U.S Commercial Nuclear Power Historical Perspective, Current Status, and Outlook, DOE/EIA-0315

(Washington, DC, March 1982), p. 10. 190Energy Information Administration, Annual Energy Review 1984, DOE/EIA-0384(84) (Washington, DC, July 1985), p. 171. 191Energy Information Administration, Thermal-Electric Plant Construction Cost and Annual Production Expenses&1979, DOE/EIA-0323(79)

(Washington, DC, May 1982), p. 10. 192Energy Information Administration, Fuel Choice in Steam Electric Generation: A Retrospective Analysis, EIA-MO12 (Washington, DC,

October 1985), Table 2.

New technology introduced during this period included

automated controls and computers. Technological

advances during the 1960s were led by the growth of

commercial nuclear power. Facing continued high

demand growth and encouraged by performance of

small nuclear facilities, utilities began ordering many

more nuclear units of far greater size and still

undemonstrated efficiency. In contrast to the 837 megawatts of new capacity ordered in the 1950s, with units

averaging fewer than 150 megawatts, in the 1960s, 86,596

megawatts were ordered, averaging about 850 megawatts per unit.189 Generation by nuclear power rose to

over 1 percent of the U.S total by 1970.190

During the 1960s some signs of difficulties in the electric

utility industry began to appear. First, environmental

requirements became a noticeable component of electric

utility costs. Coal-fired power plants began to experiment with emission control equipment to decrease the

amount of sulfur dioxide (SO2) emitted into the atmosphere. Tall emission stacks were introduced to disperse

SO2. Further, the National Environmental Policy Act of

1969 (NEPA, P.L. 91-190) required utilities seeking

Federal permits for new power plants to prepare and

defend environmental impact statements (EISs) as a part

of the permit process. Second, the increasing efficiencies

historically characterizing the industry flattened in the

mid-1960s. From 1960 to 1970, the average size of

thermal plants more than doubled. Heat rates, on the

other hand, declined only a little, from about 10,800 Btu

per kilowatthour to 10,500 Btu per kilowatthour.191

Finally a major Northeastern power blackout in 1965

raised concerns about the reliability of the huge interconnected, interdependent power networks. Response to

the blackout included formation of the North American

Electric Reliability Council (NERC) and its regional

reliability councils to promote the reliability and

adequacy of bulk power supply.

Years of Challenge: 1971-1984

The 1970s

During the 1970s, the electric utility industry moved

from decreasing unit costs and rapid growth to

increasing unit costs and slower growth. Among the

major factors affecting the electric utility industry during

the period were general inflation, increases in fossil-fuel

prices, environmental concerns, conservation, and problems in the nuclear power industry.

First, electric utilities with ambitious capital expansion

programs heavily financed by borrowing were particularly affected by inflation. As technical and regulatory

requirements increased construction lead times, the

impact of inflation was compounded.

Second, in the 1970s all fossil-fuel prices rose sharply.

Petroleum costs more than doubled in 1974 alone and

increased an average of over 26 percent a year for the

1970-1980 period. Natural gas prices, accelerated by

decontrol under the Natural Gas Policy Act (NGPA, P.L.

95-621), rose by over 23 percent a year, with the largest

increases occurring after 1978. Coal price increases averaged almost 16 percent a year.192

Third, during the 1970s environmental legislation increased the costs of building and operating electric

utility (particularly coal-fired) power plants. The Clean

Air Act of 1970 (CAA, P.L. 91-604) and its amendments

in 1977 (P.L. 95-95) required utilities to reduce pollutant

emissions, particularly SO2, causing increases in capital,

fuel, and operating costs. The Act also limited use of tall

stacks to disperse emissions. The Federal Water Pollution Control Act of 1972 (“Clean Water Act,” P.L.

92-500) limited utility waste discharges into water. In

addition, the Resource Conservation and Recovery Act

of 1976 (RCRA, P.L. 94-580) directed standards for

disposal of both hazardous and nonhazardous utility

wastes.

Finally, conservation legislation effectively barred utilities from wider use of natural gas and petroleum. The

Energy Supply and Environmental Coordination Act of

1974 (ESECA, P.L. 93-319) allowed the Federal Government to prohibit electric utilities from burning natural

gas or petroleum. The 1978 Powerplant and Industrial

Fuel Use Act (FUA, P.L. 95-620) succeeded ESECA and

extended Federal prohibition powers. The National

Energy Conservation Policy Act of 1978 (NECPA, P.L.

95-619) required utilities to provide residential consumers free conservation services to encourage slower

growth of electricity demand.
116 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

193Energy Information Administration, U.S. Commercial Nuclear Power Historical Perspective, Current Status, and Outlook, DOE/EIA-0315

(Washington, DC, March 1982), p. 10. 194Energy Information Administration, Survey of Nuclear Power Plant Construction Costs 1983, DOE/EIA-0439(83) (Washington, DC,

December 1983), p. 8. 195Energy Information Administration, U.S Commercial Nuclear Power Historical Perspective, Current Status, and Outlook, DOE/EIA-0315

(Washington, DC, March 1982), p. 10. 196Energy Information Administration, Survey of Nuclear Power Plant Construction Costs 1984, DOE/EIA-0439(84) (Washington, DC,

November 1984), p. 15. 197Energy Information Administration, Annual Energy Review 1984, DOE/EIA-0384(84) (Washington, DC, July 1985), pp. 179, 187.

Expected high electricity demand growth did not

materialize in the 1970s. Instead, capacity growth

began to outrun increases in demand. For the first time

in the history of U.S. electric power, electricity prices

rose consistently, with nominal price increases

averaging 11 percent a year. Consequently, demand

and generation growth moderated to just over 4

percent a year. However, capacity growth continued at

a rate of 6 percent a year. Slackened demand growth,

coupled with completion of expensive new capacity,

left utilities with excess capacity and without new

revenues to pay for it. As a result, some electric utilities

suffered financial setbacks and incurred declining

investor confidence.

The commercial nuclear power industry expanded

rapidly but also met serious reverses. From 1971

through 1974, 131 new nuclear units were ordered, at

an average capacity of about 1,100 megawatts.193 As a

result, inflation, labor, and materials cost increases

quickly affected construction costs of nuclear power

plants, while high interest rates raised financing costs.

Capital costs rose from about $150 per kilowatt in 1971

to more than $600 after 1976.194 Utilities building

commercial nuclear facilities faced financial difficulties

in justifying and meeting these increased costs. Safety

concerns increased. First, in February 1979 the Nuclear

Regulatory Commission (NRC) shut down five

operating reactors following concerns about durability

during earthquakes. Then, on March 28, 1979, the

Nation's most significant commercial nuclear accident

occurred at the Three Mile Island Number 2 reactor

near Harrisburg, Pennsylvania. 

These events heightened public concerns and spurred

opposition to commercial nuclear power. As a result of

higher costs, slackening electricity demand growth,

and public concern, demand for nuclear power plants

dropped quickly in the mid- and late-1970s. After 1974,

new orders plummeted and cancellations accelerated.

No new reactor orders were placed after 1978. Moreover, 63 units were canceled between 1975 and 1980.195

The Early 1980s

The early 1980s were marked by almost no growth in

the U.S. electric utility industry. In 1982 total net

generation dropped more than 2 percent, the first

absolute decline since 1945. In the mid-1980s, however,

the industry returned to moderate if unspectacular

growth.

Cost and price increases continued to slow the growth

of electric power in the early 1980s. Costs of new

nuclear power plants increased to more than $1,200 per

kilowatt of capacity in the early 1980s.196 High inflation

ensured increases in other financial and operating

costs. As a result, electricity prices rose sharply.

Average end-use electricity prices (nominal) increased

by almost 19 percent in 1980, 15 percent in 1981, and

12 percent in 1982. End-use electricity consumption

responded to rising prices and a sluggish economy by

increasing only 1 percent in 1980 and 2.5 percent in

1981. Demand then dropped almost 3 percent in 1982,

because of a decline in industrial electricity use of

nearly 10 percent, as part of that year's severe economic

downturn.197

Electricity generation increased in 1983 to a record high

of 2,310 billion kilowatthours. Capacity, however, grew

by little more than 1 percent over 1982, the smallest

increase since 1956. Industrial electricity use grew most

rapidly among end-use sectors, rebounding from its

1982 decline. The average price of electricity increased

by 2.6 percent, less than the rate of inflation. In 1984,

electricity posted its largest single-year increase in

generation since 1976, 4.5 percent. Though not large by

historic standards, the growth rate reflected a healthy

economy, generally increasing preference for electricity, and a decline in electricity's price relative to

other forms of energy. Capacity grew by 2.1 percent in

1984, led by coal-fired and nuclear-powered additions.

Electricity prices increased at the rate of inflation,

leaving real prices unchanged.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 117

198Energy Information Administration, Annual Energy Review 1984, DOE/EIA-0384(84) (Washington, DC, July 1985), pp. 171, 179, 181,

187.199Reprinted from The Changing Structure of the U.S. Electric Power Industry, 1970-1991, DOE/EIA-0562 (Washington, DC, March 1993),

pp. vii-ix. 200Edison Electric Institute, 1991 Capacity and Generation of Non-Utility Sources of Energy (Washington, DC, November 1992), p. 21.

From 1980 through 1984, net electricity generation grew

an average of a mere 1.4 percent annually. End-use sales

grew by only 2.1 percent a year, the slowest rate of

growth since the early years of the Great Depression.

Capacity, however, increased 2.3 percent a year, further

raising reserves available to meet unexpected demand.

Nuclear capacity additions entering commercial service,

despite the absence of new orders, led the rate of new

capacity growth, increasing by 6.1 percent a year. Prices

rose by approximately 8 percent a year. Commercial

electricity use increased more than any other end use,

averaging almost 4.5 percent a year; industrial end use

grew less than 1 percent a year.198

Nonutility Growth: The Late 1980s199

In 1970, electric utilities supplied 93 percent of the electricity generated in the United States. The balance was

produced by “nonutilities”&generators of electric power

that are not utilities&consisting primarily of industrial

manufacturers that produced electricity for their own

use. The electric utility share of electric power generation increased steadily between then and 1979, when it

reached 97 percent. The trend reversed itself in the

1980s, and by 1991 the electric utility share declined to

91 percent.

 Increasingly, nonutilities were generating electricity not

only for their own use but also for sale to electric utilities

for distribution to final consumers. In 1991, nonutilities

owned about 6 percent of the electric power generating

capacity and produced about 9 percent of the total

electricity generated in the United States.200

About one-half of 1991 nonutility capacity was located

in the West South Central Census Division, particularly

in Texas, and the Pacific Contiguous Census Division,

particularly in California. Most nonutilities in Texas,

which produced 49 billion kilowatthours of electricity in

1991, were engaged in chemical manufacturing, which

provides many opportunities for generating electricity

along with another form of energy (such as heat or

steam). In California, which produced 53 billion kilowatthours in 1991, most nonutilities were engaged

primarily in electricity generation.

In 1991, nonutilities produced 49 percent of their electricity from natural-gas-fired boilers, much more than

from any other single primary energy source. In contrast, utilities produced the majority of their electricity

by burning coal, and their second major source of energy

was nuclear power. Renewable energy sources, except

for hydroelectric power, were virtually untapped by

electric utilities, while renewable fuels (including wood

and waste) collectively produced the second largest

share (34 percent) of nonutility electricity. One reason

for the difference was that the majority of nonutility

capacity was in the manufacturing sector of the economy, particularly in the chemical and paper industries.

Both industries produce wastes as byproducts of the

manufacturing process that can be used as a source of

energy to drive electricity generators. Also, paper manufacturing uses a renewable fuel (wood) as a raw material

in producing paper, making wood and wood waste

easily accessible to paper manufacturers as an energy

source for electricity generation. 

As of December 1991, the process of change in the

structure of the electric power industry had not yet run

its course. Major issues arose, including the effect of the

changing industry structure on the reliability of electric

power supply and on bulk (wholesale) power trade.

Also at issue was whether the Clean Air Act Amendments of 1990 (CAAA90) would alter the course of

nonutility growth.

The concern with the CAAA90 centered on whether

nonutilities would be able to obtain a sufficient number

of emission allowances to operate in compliance with the

Amendments. Beginning in 2000 (with an incremental

phase for utilities beginning in 1995), the Amendments

require virtually all suppliers of wholesale electric

power to obtain emission allowances for any sulfur

dioxide released into the atmosphere. Utilities have been

allocated most of these allowances. Nonutilities must

obtain the allowances they need from utilities or from a

sale or auction administered by the Federal Government.

Conclusion

This appendix has summarized the past 100 years with

respect to the history of the electric power industry. The

following appendix provides an interesting look at

milestones in the history of the industry.
Appendix C

Pending Federal

Restructuring Legislation
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 133

Appendix C

Pending Federal Restructuring Legislation

(As of May 1, 2000)

106th Congress House of

Representatives Bills

H.R. 341

Environmental Priorities Act of 1999

Introduced on January 19, 1999 by Representative Robert

Andrew (D-NJ).

 Gives the Environmental Protection Agency (EPA)

the authority to establish a National Environmental Priorities Board, and requires the EPA

Administrator to promulgate a final rule containing the rules and procedures of the Board. The

Board is to support State environmental projects,

and may include loans, loan guarantees, grants,

capitalization grants, and other assistance.

 Mandates that retail electric service providers

must contribute 10 percent of the total consumer

savings to the Environmental Priorities Board once

retail electric service choice has been established.

H.R. 667

The Power Bill

Introduced by Representative Richard Burr (R-NC) on

February 10, 1999.

 Clarifies States’ authority to order retail wheeling

and imposes reciprocity requirements with respect

to sales of electricity by out-of-state entities.

 Grants cooperatively owned sellers or distributors

of electricity the right to engage in any activity or

provide any service lawfully carried out by any

other seller or distributor of electricity in the State.

 Authorizes a State or State regulatory authority to

impose charges upon purchases of retail electric

energy services, including fees: (1) to recover costs

incurred by an electric utility that become

unrecoverable due to the availability of retail

electric service choice; (2) to pay all reasonable

costs associated with governmental requirements

regarding decommissioning of nuclear generating

units; and (3) to fund public benefit programs.

 Declares that, as of January 1, 1999, new electric

utility contracts for purchase or sale shall no

longer be subject to cost provisions of Section 210

of the Public Utility Regulatory Policies Act of

1978. Additionally, authorizes recovery of all costs

associated with prior contracts involving

purchases of electric energy or capacity from a

cogeneration and small power production facility

by electric utilities.

 Repeals the Public Utility Holding Company Act

of 1935. Prescribes guidelines for Federal and

State access to books and records of electric utility

holding companies and their affiliates to ensure

consumer rate protection.

 Requires State laws or regulations for the recovery

of stranded costs to be filed with FERC as a prerequisite to State receipt of Federal energy

assistance. Precludes any modification or repeal of

such laws or regulations for 7 years after such

filing date.

 Instructs the Secretary of Energy to present a

status report (2 years after enactment of proposed

legislation) to the Congress on the extent to which

State actions have removed regulatory and

statutory barriers to interstate commerce in

electricity.

H.R. 721

Bond Fairness and Protection Act of 1999

Introduced by Representative J.D. Hayworth (R-AZ) on

February 11, 1999.

 Amends the Internal Revenue Code of 1986 (with

respect to tax-exempt bond financing of certain
134 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

electric facilities) to exclude a permitted open

access transaction (as defined by this Act) from the

definition of private business use.

 Grants public power utilities the option of grandfathering outstanding tax-exempt debt subject to

abrogating issuing tax-exempt bonds to finance

new facilities in the future. Alternatively, they may

continue to issue tax-exempt bonds subject to

current private use limitations in the tax code.

H.R. 971

Electric Power Consumer Rate Relief Act of 1999

Introduced by Representative James Walsh (R-NY) on

March 3, 1999.

 Amends the Public Utility Regulatory Policies Act

of 1978 (PURPA) to provide that a State regulatory

authority may ensure that rates charged by

qualifying small power producers and qualifying

cogenerators to purchasing utilities are (1) just and

reasonable to consumers of the purchasing utility

and (2) do not exceed the incremental cost to the

purchasing utility of alternative electric energy and

capacity at the time of delivery.

 Grants States the ability to establish programs for

monitoring the operating and efficiency performance of in-state cogeneration and small power

production facilities to determine whether such

facilities meet FERC standards for qualifying

cogenerators.

 Allows a State regulatory authority to require that

any contract entered into before the enactment

date of proposed legislation be amended to

conform to the requirements governing rates to

retail customers.

H.R. 1138

Ratepayer Protection Act

Introduced by Representative Cliff Stearns (R-FL) on

March 16, 1999.

 Mandates that the Public Utility Regulatory

Policies Act of 1978 (PURPA) requirement that

electric utilities enter into contracts to purchase

electricity from certain cogeneration and small

power production facilities shall expire after

January 6, 1999.

 Mandates that all power purchase contracts which

were in effect up to January 6, 1999 be honored.

 Directs the Federal Energy Regulatory Commission (FERC) to ensure that utilities are not

required to absorb costs associated with electric

energy or capacity purchases executed prior to the

enactment of proposed legislation.

H.R. 1253

A Bill to Amend the Internal Revenue Code of 1986 to

Restrict the Use of Tax-Exempt Financing by Governmentally

Owned Electric Utilities and to Subject Certain Activities of

Such Utilities to Income Tax

Introduced by Representative Phillip English (R-PA) on

March 24, 1999.

 Narrows the Internal Revenue Tax Code definition

of circumstances under which governmentally

owned electric utilities may finance utility facilities

with tax-exempt bonds.

 Subjects utility-related income of governmental

entities to Federal income tax in situations where

the income is derived from sources outside their

specified service area.

H.R. 1486

Power Marketing Administration Reform Act of 1999

Introduced by Representative Bob Franks (R-NJ) on

April 20, 1999.

 Requires the Secretary of Energy to develop and

implement procedures to ensure that the Federal

Power Marketing Administrations (FPMAs) utilize

the same accounting principles and requirements

as the Federal Energy Regulatory Commission

(FERC).

 Requires each FPMA and the Tennessee Valley

Authority (TVA) to submit periodically, for FERC

review, rates for the sale or disposition of Federal

energy that will ensure recovery of all their costs

in generating and marketing such energy.

 Prescribes rate mechanism and pricing guidelines.

 Establishes a fund within the Department of the

Interior to (1) mitigate damage to environmental

resources attributable to power generation and

sales facilities, and (2) restore the health of such

resources, including fish and wildlife. Mandates

project-specific mitigation plans for each power

generation project.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 135

 Establishes a fund within the Department of

Energy for renewable resources. Prescribes expenditure guidelines.

  Mandates that public bodies and cooperatives be

given a preference for future power allocations or

reallocations of Federal power through a right of

first refusal at market prices.

  Instructs the Secretary of Energy to require each

FPMA to (1) assign personnel and incur expenses

solely for authorized power marketing, reclamation, and flood control activities, and not for diversification into ancillary activities; and (2) make

annual public disclosures of its activities, including

the full costs of power projects and marketing.

  Precludes an FPMA from entering into or renewing any power marketing contract for a term

exceeding 5 years.

 Requires provision of FPMA transmission services

on an open access basis, and at FERC-approved

rates in the same manner as provided by any

public utility under FERC jurisdiction.

 Grants FERC rate-making approval authority until

a full transition is made to market-based rates, for

(1) rate schedules recommended by the Secretary

of Energy; and (2) rate schedules for FPMA power

sales.

  Amends: (1) the Department of Energy Organization Act to reflect the changes made by this Act;

and (2) specified Federal law to repeal the prohibition against the use of appropriated funds for

purposes relating to the possibility of changing

from an “at cost” to a “market rate” or any other

noncost-based method for pricing Federal hydroelectric power. 

H.R. 1587

Electric Energy Empowerment Act of 1999

Introduced by Representative Cliff Stearns (R-FL) on

April 27, 1999.

 Amends the Federal Power Act (FPA) to empower

the States to order electric utilities within their

jurisdiction to provide nondiscriminatory open access through functionally unbundled transmission

and local distribution services to retail customers

within their borders. Prescribes implementation

guidelines.

 Allows States or State regulatory authorities to

impose charges for recovery of stranded costs to

ensure reliability and availability of electric

supply, to support low-income residential programs, to retrain electric employees, to fund

environmental programs, and to provide payment

for reasonable costs associated with nuclear

decommissioning.

  Amends FPA by placing the State in charge of

regulation of bundled electric retail sales and

unbundled local distribution service.

  Authorizes FERC to distinguish, after consulting

with appropriate State regulatory authorities,

between facilities used for transmission and

delivery that are subject to FERC approval and

those subject to State jurisdiction.

 Encourages creation of Independent Transmission

System Operators to ensure that all sellers and

buyers of electricity have access to nondiscriminatory transmission services.

 Requires public power utilities to conform to open

access requirements currently applied to private

power utilities.

  Repeals mandatory power purchase contract

requirements set forth in the Public Utility Regulatory Policies Act of 1978 and allows for recovery of

stranded costs.

  Repeals the Public Utility Holding Company Act

of 1935.

  Authorizes Federal and State authorities access to

books and records of all companies in a holding

company system and for Federal oversight of

affiliate transactions for the purpose of protecting

consumers with respect to rates.

  Advocates the formation and operation of an

Electric Reliability Council to ensure that competitive restructuring of the electricity industry

does not lessen reliability of the electric supply.

Prescribes guidelines for formation, membership,

funding, and governance.
136 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

H.R. 1828

Comprehensive Electricity Competition Act

Introduced by Representative Tom Bliley (R-VA) on

May 17, 1999.

  Provides a flexible mandate for States to require

open access to the distribution facilities of regulated and non-regulated electric utilities. Allows

State-regulated and non-regulated utilities to “opt

out” of retail competition if, after a hearing before

the State regulatory authority, it is determined that

retail competition will have a negative impact on

certain customer classes.

  Grants to any person the ability to bring an action,

in the appropriate State court, against a State regulatory authority or distribution utility for failure to

comply with open access requirements.

  Eliminates private use limitations on outstanding

bonds for publicly owned facilities used in connection with retail competition or open access

transmission. Ends the issuance of new taxexempt bonds for generation or transmission.

Continues availability of tax exempt bonds for

distribution facilities under current law.

  Allows States and non-regulated utilities to determine the amount of recoverable stranded costs.

Grants FERC authority to establish stranded cost

recovery in the absence of State authority.

 Grants FERC authority to oversee creation of Independent Regional System Operators (IRSOs) and

to compel utilities to turn over control of their

transmission facilities to such organizations.

  Encourages regional agreements that facilitate

coordination among States with regard to siting

and planning of transmission and generation

facilities; calls for FERC approval of such agreements.

  Creates a renewable portfolio system mandating

that power sellers use a percentage of non-hydro

electric renewable technology. Sets forth requirements of sale and purchase of renewable energy

credits and stipulates use of revenue from such

sales.

  Authorizes FERC, upon petition by a State, to

require generators to submit a plan mitigating

market power which FERC can accept or modify.

Clarifies FERC merger review over generationonly companies and holding companies.

  Requires FERC to approve and oversee an organization that prescribes and enforces mandatory

reliability standards.

  Clarifies the authority of the Environmental Protection Agency to require an interstate trading

system for the purpose of reducing nitrogen oxide

pollution.

  Creates a Public Benefits Fund for low-income

assistance, energy efficiency programs, consumer

education, and development of emerging technologies. Stipulates funding mechanisms and sets

forth guidelines of operation.

  Repeals the Public Utility Holding Company Act

of 1935 (PUHCA) 18 months after enactment of

proposed legislation. Grants FERC and States

access to utility books and records.

  Eliminates obligatory power purchase contracts

mandated in the Public Utility Regulatory Policies

Act of 1978 on the date of enactment of proposed

legislation. 

  Places Tennessee Valley Authority (TVA) transmission under FERC jurisdiction. Subjects power

wheeled through TVA to open access requirements and allows wholesale electric power sales

by TVA outside of their traditional service area.

Calls for the renegotiation of long-term contracts

and authorizes FERC to intervene if conflict arises.

Authorizes TVA to join an Independent System

Operator.

  Authorizes FERC to determine transmission rates

for the Bonneville Power Administration, Western

Area Power Administration, and the Southwestern

Power Administration, and allows these Federal

Power Administrations to impose a surcharge on

sales to recover costs of environmental programs

and to join IRSOs.

  Provides States that have implemented retail

competition with the authority to preclude an outof-state utility with a retail monopoly from selling

within the State unless that out-of-state utility

permits customer choice.

 Requires States electing retail competition to establish terms and conditions to protect consumers,

including rates that are just and reasonable,

measures to ensure privacy of consumer infor-
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 137

mation and that prohibit discriminatory practices

by electric utilities. Allows States to impose nonbypassable fees to fund such programs. Authorizes creation of a publicly accessible database that

will provide information to consumers on electric

utilities which participate in retail competition.

  Amends PURPA by allowing net metering for

renewable energy and granting tax credits for

production of energy from renewable resources

and production of energy efficient buildings.

  Grants customers the ability to acquire retail electric energy on an aggregate basis if the group of

customers is served by one or more local distribution companies which sell electricity on a

competitive basis.

  Authorizes the provision of grant money for

assistance purposes to tribal Indians, Southeast

Alaska, and rural and remote communities.

 Eliminates antitrust review by the Nuclear Regulatory Commission and amends the Internal

Revenue Code relating to deductions to a qualified

nuclear decommissioning fund.

H.R. 2050

Electric Consumers’ Power to Choose Act of 1999

Introduced by Representative Steve Largent (R-OK) on

June 8, 1999.

 Accords States a flexible mandate in terms of retail

competition. States may choose to implement retail

electric competition for their regulated distribution

systems, or choose to opt out if retail competition

would negatively impact customers. Nonregulated

local distribution companies are also provided

with a similar flexible mandate to establish or opt

out of retail competition.

  Grandfathers State plans already underway or on

the books and provides a reciprocity provision to

keep out companies whose territories are not open

to competition. Similar plans adopted by nonregulated local distribution companies will also be

grandfathered.

  Amends tax laws to permit public power and

municipal utilities to participate in open access

plans without forfeiting the tax-exempt status of

their outstanding bonds.

  Permits States and nonregulated utilities to bar

those who have not elected retail choice from

selling to electric customers in their State or utility

service regions. 

  Allows a group of electric customers to buy retail

electricity on an aggregate basis if they are served

by one or more electric utilities in consumer choice

regions.

  Provides that States will have jurisdiction over

disputes arising from States’ or nonregulated

utilities’ actions in electing to move to retail

competition.

 Directs the Federal Trade Commission to establish

rules and penalties to protect consumers from

unfair trade practices by electricity suppliers.

  Amends the Federal Power Act (FPA) to require

that electric suppliers and transmitting utilities join

an Electric Reliability Organization subject to

FERC approval and oversight. Protects such

organizations from the provisions of anti-trust

laws.

  Allows small-scale power generators to interconnect with local distribution utilities to facilitate

supplies that are closer to end-use requirements.

  Directs FERC to determine the exercise of market

power by an electric utility and to initiate mitigation measures where necessary. 

  Extends FERC’s authority over transmission facilities of electric utilities to include facilities of State

and municipal utilities, rural electric cooperatives,

and facilities that qualify under the Public Utility

Regulatory Policies Act of 1978, thus enabling the

Commission to set transmission rates for all

utilities in the country.

 Clarifies State and Federal authority over bundled

and unbundled retail electric sales by granting

FERC exclusive regulatory authority over the

transmission component of an unbundled retail

sale.

  Provides FERC with the authority to establish

Regional Transmission Organizations (RTOs) by

requiring that all transmitting utilities transfer

operational control or ownership of their transmission facilities to such an organization.
138 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

 Authorizes FERC to order the BPA and the Electric

Reliability Council of Texas to wheel power.

  Requires FERC to review mergers and property

dispositions involving generation-only companies

and holding companies.

 Encourages regional agreements that facilitate

coordination among States with regard to siting

and planning of transmission and generating

facilities subject to approval by FERC of such

agreements.

 Requires States electing retail competition to establish terms and conditions to protect consumers,

including rates that are just and reasonable,

measures to ensure privacy of consumer information and that prohibit discriminatory practices

of electric utilities. Allows States to impose nonbypassable fees to fund such programs.

  Exempts holding companies from limitations of

the Public Utility Holding Company Act of 1935

eighteen months after enactment of proposed

legislation unless they provide retail service in two

or more States that do not provide open access.

Grants FERC and States access to utilities’ books

and records to assist regulatory authorities in

carrying out their functional responsibilities.

 Prospectively repeals the Public Utility Regulatory

Policies Act of 1978 and eliminates obligatory

power purchase contracts. Allows for recovery of

stranded costs with respect to purchases from

outstanding contracts.

 Places TVA transmission under FERC jurisdiction.

Subjects power wheeled through TVA to open

access requirements and sets limitations on electric

power sales by TVA. Prohibits the acquisition of

new generating resources and calls for the

renegotiation of long-term contracts. Repeals

TVA’s jurisdiction to regulate municipality or

cooperative organization distributors and removes

TVA’s PURPA ratemaking authority. Allows for

imposition of charges for the purpose of stranded

cost recovery. 

 Subjects BPA to relevant provisions of the FPA for

purposes of BPA’s transmission systems, but

provides that any determination by FERC would

be subject to a list of conditions, including a

requirement that the rates and charges are sufficient to recover existing and future Federal

investment in the Bonneville Transmission System.

Requires FERC to establish a rate recovery mechanism to meet BPA’s cost recovery requirements.

  Subjects Power Marketing Administrations

(PMAs) to the same accounting principles used by

other public utilities and applicable antitrust laws

and authorizes PMAs to participate in FERCapproved RTOs.

  Mandates a renewable portfolio generation minimum standard of 3 percent of total generation and

sets forth enforcement procedures for noncompliance. Directs the Secretary of Energy to

establish a program to issue, monitor the sale and

exchange of, and track Renewable Energy Credits.

 Amends the Public Utility Regulatory Policies Act

of 1978 by allowing net metering for renewable

energy, and granting tax credits for production of

energy from renewable resources and production

of energy efficient buildings.

H.R. 2363

Public Utility Holding Company Act of 1999

Introduced by Representative W.J. (Billy) Tauzin (R-LA)

on June 25, 1999.

  Repeals the Public Utility Holding Company Act

of 1935.

 Enacts the Public Utility Holding Company Act of

1999 to support the continuing need for limited

Federal and State regulation and to supplement

the work of State commissions for the continued

rate protection of utility customers.

H.R. 2569

Fair Energy Competition Act of 1999

Introduced by Representative Frank Pallone, Jr. (D-NJ)

on July 20, 1999.

 Aims that older and more polluting power generating units internalize pollution costs on par with

newer and less polluting generation units.

 Requires FERC to (1) calculate generation performance standards for nitrogen oxides, carbon

dioxide, mercury, sulfate fine particulate matter,

and any other significant air pollutant released in

significant quantities by electric generating units

from covered generating units, (2) set forth

schedules of statutory tonnage caps for electric

generation emissions of nitrogen oxides, carbon
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 139

dioxide, mercury, and sulfate fine particulate

matter, and (3) promulgate, by rule, a national

limit on total annual emissions of any other

pollutant from electric generating units.

  Prescribes rules for allocation and trading of

allowances and sets penalties for excess emissions.

  Mandates that, during periods when National

Ambient Air Quality Standards for ozone are

exceeded, certain generating units shall be

required to “adjust (their) reported actual

emissions.”

  Amends the Federal Power Act to require the

Commission to provide estimates of electricity

generation from covered electric generation units

with projections of demand growth for regions

and time periods specified in the legislation. 

  Directs the Secretary of Energy to establish a

National Electric System Public Benefits Board

authorized to collect wires charges to fund public

purpose programs including renewable sources,

universal/affordable electric service, energy conservation and efficiency programs, research and

development programs, and assistance to lowincome families.

  Creates a renewable energy portfolio (to become

effective upon the enactment of proposed legislation) that mandates renewable electricity generation to increase from 2.5 percent in 2000 to 7.5

percent in 2010. Authorizes FERC to sell renewable

energy credits (that equal the number of megawatthours of electricity from renewables) and to

utilize proceeds to fund research and development

of renewables and cleaner burning fuels.

  Amends the Public Utility Regulatory Policies Act

of 1978 (PURPA) to net metering to producers of

renewable electricity and sets guidelines for interconnection to the grid. Also, stipulates disclosure

requirements of emissions and generation data

with respect to sales of electricity to consumers.

  Eliminates obligatory power purchase contracts

mandated in PURPA on the date of enactment of

proposed legislation without invalidating the

sanctity of existing contracts. 

  Sets forth terms and conditions to protect consumers (including privacy and non-discriminatory

measures) and sets penalties for violations.

H.R. 2602

National Electricity Interstate Transmission Reliability Act

Introduced by Representative Albert Wynn (D-MD) on

July 22, 1999.

  Amends the Federal Power Act to accord FERC

jurisdiction over an electric reliability organization

(ERO), affiliated regional reliability entities, system

operators, and users of the bulk-power system for

enforcing compliance with respect to transmission

reliability standards.

  Prescribes procedures that enable FERC to

approve reliability standards (subject to the

requirement that the standards are nondiscriminatory and in the public interest) for the bulk-power

system and to approve an entity’s application to

function as an ERO contingent on its capability to

meet criteria listed in the proposed legislation.

  Authorizes FERC to take disciplinary action

against those violating organizational reliability

standards.

H.R. 2645

Electricity Consumer, Worker, and Environmental Protection

Act of 1998

Introduced by Representative Dennis Kucinich (D-OH)

on July 29, 1999.

  Prescribes standards for electricity services at the

State and Federal levels.

  Provides protections for electric utility workers

whose companies are undergoing transfer of

ownership as a result of restructuring.

  Ensures consumers’ right to privacy with respect

to billing, payments, usage, and dispute resolution.

  Mandates that each State create a not-for-profit

membership corporation to represent and promote

the interests of States’ residential electricity consumers.

  Requires each provider of distribution services

and supplies to submit monthly reports to monitor

performance and reliability to help protect

consumers.

  Establishes within the Federal Energy Regulatory

Commission an office of the Consumer Council to

represent energy consumers.
140 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

  Prohibits State or Federal authorities from imposing a stranded cost recovery burden on existing

consumers.

  Sets limits with respect to affiliate ownership on

State-regulated investor-owned utilities.

 

  Directs that utilities set aside adequate financial

resources to meet the costs of nuclear decommissioning and waste disposal activities.

  Reinforces FERC’s authority to review electric

utility mergers.

  Requires the Environmental Protection Agency to

promulgate regulations establishing nationwide

pollution standards together with pollutant monitoring procedures.

 Establishes a National Electric Public Benefit Board

to provide funds (gathered through the imposition

of a wires charge) to States for low-income

assistance programs.

  Establishes renewable energy portfolio standards

for electricity generation to reach 8 percent in the

year 2010 (increasing by 1 percent annually thereafter) by requiring the Secretary of Energy to

implement the standards in accordance with the

provisions of the proposed legislation.

 Amends the Public Utility Regulatory Policies Act

of 1978 to provide net-metering and interconnection facilities for renewable energy, where

necessary.

  Sets deadlines for States to comply with the

requirements of this Act subsequent to their deregulating retail electricity sales.

  Directs States not to permit customer classes to be

charged rates for transmission and distribution in

excess of their proportional responsibility for

providing these services.

  Requires that utilities transfer their transmission

and distribution assets to regulated counterparts/affiliates after deregulation of electricity

sales at the retail level. Also, provides detailed

guidelines to prevent affiliate abuse and crosssubsidization.

  Limits utilities’ ownership of power plants to

prevent exercise of market power in electricity

generation.

 Sets forth post-deregulation requirements for compliance in areas such as the provision of basic

services, aggregation of customers, worker protection, and rules for electricity suppliers and

distribution companies.

  Prohibits unfair business practices and stipulates

norms to protect the consumers in billing,

metering, and in securing credit. Remedies for

violation are also provided.

H.R. 2756

Fair Competition in Tax-Exempt Financing Act of 1999

Introduced by Representative Ralph Hall (D-TX) on

August 5, 1999.

  Amends the Internal Revenue Code of 1986 by

eliminating the issuance of tax-exempt bonds to

finance public projects to prevent governmental

entities from using tax-exempt financing to engage

in unfair competition against private sector

facilities.

H.R. 2786

Interstate Transmission Act

Introduced by Representative Thomas Sawyer (D-OH)

on August 5, 1999.

  Expands the definition of interstate commerce in

electricity to include unbundled transmission of

electricity sold at the retail level under FERC’s

jurisdiction (in addition to transmission at the

wholesale level) and directs FERC to determine

which facilities used in interstate commerce will be

subject to FERC’s jurisdiction and which facilities

will be subject to the State’s jurisdiction.

 Authorizes FERC to permit a transmitting utility to

recover all costs incurred in connection with the

transmission and associated services including the

costs of expansion of transmission networks.

  Directs FERC to establish just and non-discriminatory rates that promote efficient transmission

and network expansion to avoid cost shifting

among customer classes.

  Directs FERC to promote and approve the

voluntary formation of regional transmission

organizations.

  Entrusts FERC with the responsibility to ensure

that transmitting utilities and their customers

comply with reliability standards adopted by

electric reliability organizations.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 141

H.R. 2944

Electricity Competition and Reliability Act

Introduced by Representative Joseph Barton (R-TX) on

September 24, 1999. 

  Gives priority to State laws that are passed up to

3 years after enactment of proposed legislation

that address concerns proffered by proposed legislation.

  Amends the Federal Power Act (FPA) to clarify

States’ authority to require retail competition and

to clarify State and Federal jurisdiction. Gives

States the authority to impose fees to fund public

purpose programs.

  Amends the FPA to require open access for all

transmitting utilities and to provide transmission

service at nondiscriminatory prices. Grants FERC

authority over the transmission systems at the

State, municipal and rural cooperative level, and

allows FERC to review transmission rates.

  Grants FERC the power to determine which

transmission facilities compose the bulk power

system (and fall under FERC’s jurisdiction) and

which are exempt from FERC regulations.

  Allows FERC to recover wholesale stranded costs

where necessary.

  Amends the FPA to permit FERC to order

domestic transmission service to be used for a

foreign country.

  Encourages the formation of RTOs. Provides

standards that RTOs must meet and authorizes

FERC to approve RTOs. Allows Federal transmitting utilities to participate in RTOs with Congressional consent. Protects RTOs formed prior to

enactment of legislation from mandatory modifications directed by FERC.

  Amends the FPA to grant Congressional consent

to regional transmission siting to ameliorate

problems encountered by States in planning for

future transmission. Authorizes FERC to review

compacts to protect the public’s interest.

  Authorizes FERC to order a transmitting utility to

expand its transmission facilities (if it would not

unreasonably harm the services provided by the

utility), but retains State and local authority over

transmission siting.

 Amends the FPA by allowing transmission utilities

to recover costs incurred to encourage additional

investment in transmission. Directs FERC to

approve transmission rates that are high enough to

ensure the expansion of transmission networks.

  Directs FERC to encourage transmission pricing

policies that encourage RTO formation, reduce

pancaking of rates, minimize cost shifting among

customer classes, encourage reliability of the

transmission system, and encourage investment in

the transmission system. Authorizes FERC to

approve transmission rates and requires FERC to

submit a report to Congress on these issues.

  Amends the FPA to allow FERC to impose civil

penalties for non-compliance with FPA regulations. Permits Federal agencies to file complaints

with FERC and seek rehearing of FERC orders.

  Amends the FPA to allow FERC jurisdiction over

an ERO, affiliated regional reliability entities, and

bulk power system users and operators to ensure

reliability. Calls for FERC review of ERO

standards and provides guidelines for the ERO’s

operation.

  Provides consumer protection measures that

address information disclosure issues, consumer

privacy practices, unfair trade practices, and

express the consensus that electric services should

be universal and affordable.

 Expands FERC merger review authority to include

all electric utilities and transmitting utilities. Eliminates antitrust review by the Nuclear Regulatory

Commission for production facilities.

  Repeals the Public Utility Holding Company Act

of 1935. Allows FERC and the State access to

records of holding and associate companies to

identify costs and to protect utility consumers’

rates.

  Prospectively repeals the Public Utility Regulatory

Policies Act of 1978 and allows for cost recovery of

purchases made prior to enactment of proposed

legislation.

  Allows retail customers to designate an entity to

aggregate purchases of electric energy. 

  Amends the FPA to require local distribution

companies to interconnect distributed generation

facilities with the local distribution facilities.
142 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

Grants FERC the ability to order interconnection

and establish safety standards. 

  Prohibits TVA from selling electric power at the

retail level with certain exceptions. Allows TVA to

only sell excess electric power and limits TVA’s

contract offerings to new customers. Places TVA

under the same standards for wholesale sales in

interstate commerce as public utilities. Authorizes

TVA to build or acquire additional generation

facilities, if needed, and directs TVA to renegotiate

existing all-requirements power contracts. Allows

stranded cost recovery by TVA.

  Provides that FERC determine transmission rates,

terms, and conditions to assure BPA adequately

recovers costs, protects customers from cost

shifting, and provides transmission access.

  Grants FERC statutory authority to approve and

modify Power Marketing Administration (PMA)

wholesale rates to guarantee full cost recovery.

Applies provisions of the FPA to the transmission

of electric energy by PMAs, and subjects PMAs to

antitrust laws

  Reauthorizes and expands the Renewable Energy

Production Incentive program established by the

Energy Policy Act of 1992. Requires retail electric

suppliers to provide net metering services.

Maintains States’ authority to set Renewable

Energy Portfolio standards.

  Directs the Department of Energy to present a report to Congress on interstate commerce in electric

energy and identify regulatory and statutory barriers. Directs FERC to study State regulation of

transmission sales and report the results to

Congress.

H.R. 2947

Home Energy Generation Act

Introduced by Representative Jay Inslee (D-WA) on

September 24, 1999.

  Amends the Federal Power Act to allow for net

metering. Requires retail electric suppliers to make

electric energy meters available (if necessary) to

consumers who have installed an energy generating unit capable of net metering. 

 Protects against discrepancies in rates and contract

terms between net metering customers and

customers who do not participate in net metering.

  Attributes energy generated through net metering

that is entitled to receive credits under a Federal

minimum energy portfolio to the retail electric

supplier and allows the retail supplier to count

these credits towards requirements for renewable

resources.

  Prescribes guidelines and procedures for the

calculation of net metering and for the purposes of

monitoring, billing, and providing consumer

protection.

  Places limits on the amount of allowable net

metering that a local distribution company retail

electric supplier is required to provide.

 Calls for open public documentation of total generating capacity, type of unit, and energy source(s)

of consumer-owned generating units.

  Provides consumer protection measures and sets

performance and safety standards for use in netmetering and interconnection to the electrical grid.

106th Congress Senate Bills

S. 161

Power Marketing Administration Reform Act of 1999

Introduced by Senator Daniel Moynihan (D-NY) on

January 19, 1999.

  Directs the Secretary of Energy to develop and

implement cost accounting procedures to ensure

that the Federal Power Marketing Administrations

(FPMAs) and TVA use the same accounting

principles and requirements that FERC applies to

the electric operations of public electric utilities.

 Mandates that the FPMAs and TVA implement

rate-adjusting procedures to allow for full cost

recovery of power they sell while transitioning to

market-based rates set by an open market.

  Requires FPMAs and TVA to develop and submit

to FERC, once every 5 years, proposed rates that

ensure recovery of all costs of generation and

marketing of power (including fish and wildlife

related costs) for approval and/or modification.

  Empowers the Secretary of Energy to establish

procedures enabling FPMAs and the TVA to

implement market-based pricing 2 years after the

enactment of legislation using bid and auction

procedures.
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 143

  Prescribes specifics regarding use of revenue collected through market-based pricing including,

among others, environmental mitigation and

restoration, renewable resource development, and

utilization of potential surpluses to reduce the

budgetary deficit.

  Precludes an FPMA or TVA from entering into or

renewing any power marketing contract for a term

exceeding 5 years from the date of enactment of

proposed legislation.

  Directs that FPMAs and the TVA provide transmission service on an open access basis at just and

reasonable rates approved by FERC.

S. 282

Transition to Competition in the Electric Industry Act

Jointly introduced by Senators Connie Mack (R-FL) and

Bob Graham (D-FL) on January 21, 1999.

  Prospectively repeals mandatory power purchase

requirements (from cogenerators and small power

producers) by the electric utilities as required by

Section 210 of the Public Utility Regulatory Policies

Act of 1978.

 Ensures recovery of power purchase contract costs

incurred by electric utilities prior to the enactment

of proposed legislation.

S. 313

Public Utility Holding Company Act of 1999

Introduced by Senator Richard Shelby (R-AL) on

January 27, 1999.

  Repeals the Public Utility Holding Company Act

(PURPA) of 1935.

  Ensures rate protection of utility customers by

empowering State and Federal regulatory

authorities with tools which permit access to the

books and records of holding companies for the

purpose of jurisdictional rate-setting activities.

 Grants the Federal Energy Regulatory Commission

additional enforcement authority under the

Federal Power Act to permit implementation of

provisions of proposed legislation.

S. 386

Bond Fairness and Protection Act of 1999

Introduced by Senator Slade Gorton (R-WA) on

February 6, 1999.

 Amends the Internal Revenue Code by eliminating

restrictions placed on public utilities which

prevent the reciprocal provision of open access

transmission and ancillary services required by

FERC Order 888.

  Grants public power utilities the option of grandfathering outstanding tax-exempt debt subject to

abrogating issuing tax-exempt bonds in the future

to finance new facilities. Alternatively, they may

continue to issue tax-exempt bonds subject to

current private use limitations in the tax code.

S. 516

Electric Utility Restructuring Empowerment and Competitiveness Act of 1999

Introduced by Senator Craig Thomas (R-WY) on March

3, 1999.

 Empowers States to regulate intrastate retail

electric supply or distribution service, establish

and enforce reliability standards, determine just

and reasonable fees where appropriate, and to

enforce open transmission and provision of

universal service.

  Grants FERC jurisdiction over wholesale electricity

transmission services, but removes sales of wholesale electricity from the scope of FERC regulation.

  Amends PURPA to exempt electric utilities from

obligatory contracts with cogenerating facilities or

small power producers.

  Repeals PUHCA.

  Allows FERC and the States access to and disclosure of holding company management and

affiliate rate recovery records. Authorizes appropriations and calls on FERC to promulgate final

rules of exemption from PUHCA.

S. 1047

Comprehensive Electricity Competition Act

Introduced by Senator Frank Murkowski (R-AK) on

May 13, 1999.

  Amends PURPA to require each distribution

utility to permit all of its retail customers to

purchase power from the supplier of their choice

by January 1, 2003, but provides a flexible mandate

for States to require open access to the distribution

facilities of regulated and non-regulated electric

utilities. Allows State-regulated and non-regulated
144 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

utilities to "opt out" of retail competition if, after a

hearing before the State regulatory authority, it is

determined that retail competition will have a

negative impact on certain customer classes.

  Allows States and non-regulated utilities to determine the amount of recoverable stranded costs.

Grants FERC authority to establish stranded cost

recovery in the absence of State authority.

  Amends PURPA to permit a State that has chosen

to implement retail competition to prohibit a

distribution utility that is not under the ratemaking authority of the State and that has not

elected to institute retail competition from selling

electricity to the consumers of the State that has

chosen retail competition. Grants non-regulated

utilities similar requirements of reciprocity.

 Allows electricity customers and entities acting on

their behalf to acquire retail electric energy on an

aggregate basis if they are served by one or more

distribution utilities for which a notice of retail

competition has been filed.

 Requires States electing retail competition to establish terms and conditions to protect consumers,

including rates that are just and reasonable,

measures to ensure privacy of consumer information and that prohibit discriminatory practices

by electric utilities. Allows States to impose nonbypassable fees to fund such programs. Authorizes the creation of a publicly accessible database

that will provide consumers information on electric utilities that participate in retail competition.

  Clarifies State and Federal authority over retail

transmission services. Expands FERC’s jurisdiction

to include authority over unbundled retail transmission and municipal and publicly owned

utilities and cooperatives. Reinforces FERC’s

authority to require public utilities to provide open

access transmission services and permit recovery

of stranded costs.

  Grants FERC authority to oversee creation of

IRSOs and to compel utilities to turn over control

of their transmission facilities to such organizations.

  Creates a Public Benefits Fund for low-income

assistance, energy efficiency programs, consumer

education, and development of emerging technologies. Stipulates funding mechanisms and sets

forth guidelines for operation.

  Creates a renewable portfolio system mandating

that sellers use, as a generation source, a percentage of non-hydro electric renewable technology. Sets forth requirements of sale and purchase of renewable energy credits and stipulates

use of revenue from such sales.

  Amends PURPA by allowing net metering for

renewable energy, and granting tax credits for

production of energy from renewable resources

and production of energy efficient buildings.

  Eliminates obligatory power purchase contracts

mandated in the Public Utility Holding Company

Act of 1935 (PUHCA) on the date of enactment of

proposed legislation.

 Amends PURPA to require a distribution utility to

allow a heat and power or a distributed power

facility to interconnect with it if the facility is

located within the distribution utility’s service

territory and complies with rules issued by the

Secretary of Energy and related safety and power

quality standards.

  Authorizes the provision of grant money for

assistance purposes to tribal Indians, Southeast

Alaska, and rural and remote communities.

  Repeals PUHCA 18 months after enactment of

proposed legislation. Grants FERC and States

access to utilities’ books and records.

  Authorizes FERC, upon petition by a State, to

require generators to submit a plan mitigating

market power that FERC can accept or modify.

Clarifies FERC merger review over generationonly companies and holding companies.

  Allows FERC to approve and oversee an ERO to

prescribe and enforce mandatory reliability

standards. 

  Clarifies the authority of the Environmental

Protection Agency to require a nitrogen oxide

(NOx) allowance cap and trading program in all

States in which a NOx emission source is located.

 Places TVA transmission under FERC jurisdiction.

Subjects power wheeled through TVA to open

access requirements and allows wholesale electric

power sales by TVA outside of their traditional

service area. Calls for the renegotiation of longterm contracts and authorizes FERC to intervene
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 145

if conflict arises. Authorizes TVA to join an Independent System Operator.

  Authorizes FERC to determine transmission rates

for the BPA, Western Area Power Administration

(WAPA), and the Southwestern Power Administration (SWPA) and allows these Federal Power

Administrations to impose a surcharge on sales to

recover costs of environmental programs and to

join IRSOs.

 Eliminates antitrust review by the Nuclear Regulatory Commission and amends the Internal

Revenue Code relating to deductions to a qualified

nuclear decommissioning fund.

S. 1048

Comprehensive Electricity Competition Tax Act

Introduced by Senator Frank Murkowski (R-AK) on May

13, 1999.

  Amends the Internal Revenue Code with respect

to tax-exempt private activity bonds to declare

that the determination whether any electric output

facility bond issued before enactment of this Act

(pre-effective date electric output facility bond) is

a private activity bond shall be made without

regard to any specified permissible competitive

action taken by the issuer. Requires such a bond

not to be a private activity bond or industrial

development bond as of the date of enactment of

this Act. Makes this Act inapplicable to any

qualified refunding bond meeting certain criteria

which is issued to refund a pre-effective date

electric output facility bond if the net proceeds of

the refunding bond are used within 90 days of

issuance to redeem the refunded bond.

  Qualifies for tax exemption private activity bonds

for electric output facilities issued after enactment

of this Act, excluding any part of an issue for

distribution property that operates at 69 kilovolts

or less.

  Modifies special rules for nuclear decommissioning costs to eliminate cost-of-service as the

maximum which a taxpayer may pay into a

Nuclear Decommissioning Fund.

  Includes any distributed power property within

15-year depreciation property.

  Establishes an 8-percent investment credit for

combined heat and power (CHP) systems property

placed in service in calendar years 2000 through

2002. Precludes any carryback of the energy credit

prior to the effective date of this Act, except for

solar and geothermal energy property.

S. 1273

Federal Power Act Amendments of 1999

Introduced by Senator Jeffrey Bingaman (D-NM) on June

24, 1999.

  Expands the jurisdiction of FERC to order retail

wheeling to facilitate transition to competition in

power generation.

  Preserves authority of States (and of their regulatory commissions) to require that jurisdictional

utilities provide unbundled local distribution

service on a nondiscriminatory basis to customers

within the State.

  Sustains States’ authority to impose charges on

retail electricity distribution and power generation.

  Directs FERC to establish and enforce reliability

standards for transmission purposes and grants

FERC the authority to set up the required

infrastructure.

  Empowers FERC to order a transmitting utility to

enlarge, extend, or improve its transmission

facilities.

  Authorizes FERC to order the formation of

regional transmission systems and regional independent system operators to ensure nondiscriminatory transmission availability within a

region by securing the participation of all transmitting utilities within regions so formed.

  Protects existing wholesale power purchase contracts and preempts any State action that would

bar recovery of associated costs by electric utilities.

S. 1284

Electric Consumer Choice Act

Introduced by Senator Don Nickles (R-OK) on June 24,

1999.

  Amends the Federal Power Act to ensure that no

State may establish, maintain, or enforce on behalf

of any electric utility an exclusive right to sell electric energy or otherwise unduly discriminate

against any consumer who seeks to purchase

electric energy in interstate commerce from any

supplier.
146 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

  Stipulates that no electricity suppliers shall be

denied access to transmission and local distribution facilities or be precluded from participating

in retail sales on grounds that such denial may be

permissible under existing State laws.

  Authorizes the State to prohibit retail electric sales

by an electric utility or its affiliates if the utility or

affiliates fail to comply with State requirements of

reciprocity.

  Repeals the Public Utility Holding Company Act

of 1935 from the date of enactment of proposed

legislation.

  Prospectively repeals mandatory power purchase

provisions required by the Public Utility Regulatory Policies Act of 1978.

  Recognizes the authority of a State to regulate

retail sales and local distribution of electric energy.

S. 1369

Clean Energy Act of 1999

Introduced by Senator James Jeffords (R-VT) on July 14,

1999.

  Directs EPA to promulgate final regulations that

establish a schedule of limits on the quantity of

each pollutant that all covered generation facilities,

(i.e., all non-nuclear facilities with a nameplate

capacity of 15 megawatts or greater that use a

combustion device to generate power) in the

aggregate, shall be permitted to emit in each

calendar year beginning in 2002. 

  Sets maximum limits for nationwide emissions of

carbon dioxide, mercury, nitrogen oxide, and

sulfur dioxide for the calendar year 2005 and each

year thereafter. 

  Requires that EPA perform an annual determination of generation performance standards for

carbon dioxide, mercury, nitrogen oxide, and sulfur dioxide emissions per megawatthour of electric

production by covered generation facilities.

 Establishes guidelines for earning emission credits

for covered generation facilities and prescribes

penalties for noncompliance with the emission

credit system.

  Prohibits a generating plant from emitting

specified pollutants if the EPA determines, upon

review, that an emissions rate of specified pollutants in excess of the generation performance

standard can be reasonably anticipated to cause or

contribute to significant adverse local impacts.

Establishes civil penalties for noncompliance.

  Directs the Secretary of Energy to establish a

National Electric System Public Benefits Board to

fund States for supporting renewable energy

sources, universal electric service, energy conservation, and other public purposes. Prescribes

funding for the Board by establishing a nonbypassable wires charge of up to 2 mills per

kilowatthour.

 Establishes Renewable Energy Portfolio Standards

and prescribes minimum requirements for electricity generation from renewable sources to

gradually increase from 2.5 percent in 2000 to 20

percent in 2020 (as a share of total electric sales).

  Requires FERC to establish standards and procedures for issuing renewable energy credits to

facilities generating electricity from renewable

sources.

  Amends PURPA to repeal its mandatory power

purchase provisions, but retains the validity of

contracts entered under such provisions prior to

the enactment of proposed legislation.

  Requires electric companies to allow a retail

electric customer to interconnect and employ a net

metering system. Sets procedures and guidelines

for net metering, and sets safety and performance

standards.

  Directs the Secretary of Energy to establish a

system of disclosure that enables retail consumers

to knowledgeably compare retail electric services

offerings, including comparisons based on generation source portfolios, emissions data, and price

terms.

S. 1949

Clean Power Plant and Modernization Act of 1999

Introduced by Senator Patrick Leahy (D-VT) on

November 17, 1999.

  Sets combustion heat rate efficiency levels for

operational and future fossil fuel-fired generating

plants, and requires each generating unit to obtain

a permit. 
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 147

  Directs the Department of Energy (DOE) and EPA

to promulgate methods of measuring compliance

levels. Allows EPA to grant waivers for heat rate

efficiency standards.

  Requires all fossil fuel-fired generating units to

comply with the air emissions standards put forth

in the Clean Air Act not later than 10 years after

the date of enactment of proposed legislation. Sets

emission rates for certain particulates and requires

each generating unit to obtain a permit within the

same timeframe. Requires the DOE and EPA to

promulgate methods for determining compliance.

  Directs the Administrator of EPA to promulgate

fuel sampling and monitoring techniques,

reporting requirements, and disposal procedures

for certain pollutants.

  Amends the Internal Revenue Code of 1986 by (1)

extending Renewable Energy Production Credits,

(2) imposing a tax on fossil fuel-fired generating

units, (3) reviewing and adjusting tax rates on a

biannual basis, and (4) creating a Clean Air Trust

Fund.

  Provides grants to publicly owned generating

units that make capital expenditures for compliance purposes.

  Grants monies to fund research and development

programs focused on generating electric power

from renewable resources, clean coal technologies,

gas turbine technologies, and combined heat and

power technologies.

  Requires DOE, the Federal Energy Regulatory

Commission, and the EPA to submit a report to

Congress within 2 years of enactment of proposed

legislation to evaluate the implementation of

proposed legislation.

  Provides dislocation and worker adjustment funds

for coal industry workers who are terminated

from employment and communities that are

adversely affected due to downsizing of the coal

industry.

  Appropriates money for the development and

implementation of carbon sequestration strategies.

S. 2071

Electric Reliability 2000 Act

Introduced by Senator Slade Gorton (R-WA) on

February 10, 2000.

 Provides that FERC shall have jurisdiction over the

electric reliability organization, all affiliated

regional reliability entities, all system operators,

and all bulk power system users.

 Allows any person, including the North American

Electric Reliability Council and its member

Regional Reliability Councils, to submit to FERC,

before designation of an electric reliability organization, any reliability standard, guidance, practice,

or amendment to a reliability standard, guidance,

or practice that the person proposes to be made

mandatory and enforceable.

 Directs FERC to (1) propose regulations specifying

procedures and requirements for an entity to

apply for designation as the electric reliability

organization not later than 90 days after the date

of enactment, (2) provide notice and opportunity

for comment on the proposed regulations, and (3)

promulgate final regulations not later than 180

days after the date of enactment.

  Mandates that the electric reliability organization

submit to FERC (1) proposals for any new or

modified organization standards, and (2) any

proposed change in a procedure, governance, or

funding provision relating to delegated functions.

 Requires the electric reliability organization, at the

request of an entity, to enter into an agreement

with the entity for the delegation of authority to

implement and enforce compliance with organization standards in a specified geographic area if

the electric reliability organization finds that the

entity satisfies certain requirements and the

delegation would promote the effective and

efficient implementation and administration of

bulk power system reliability.

  Requires each system operator to be a member of

the electric reliability organization and any

affiliated regional reliability entity operating under

an agreement applicable to the region in which the

system operator operates, or is responsible for the

operation of, a transmission facility.

 Allows the electric reliability organization to impose a penalty, limitation on activities, functions,

or operations, or other disciplinary action against

a bulk-power system user if the electric reliability

organization, after notice and an opportunity for

interested parties to be heard, issues a finding in
148 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

writing that the bulk power system user has

violated an organization standard.

  Directs the electric reliability organization to conduct periodic assessments of the reliability and

adequacy of the interconnected bulk power system

and report annually to the Secretary of Energy and

the Commission its findings and recommendations

for monitoring or improving system reliability and

adequacy.

  Prescribes all appropriate steps that the electric

reliability organization shall take to gain recognition in Canada and Mexico.

S. 2098

Electric Power Market Competition and Reliability Act 

Introduced by Senator Frank Murkowski (R-AK) on

February 24, 2000.

Title I: Amendments to the Federal Power Act 

  Amends the Federal Power Act to (1) place within

the ambit of Federal regulation unbundled interstate transmission of electric energy sold at retail,

and (2) place within the jurisdiction of the State

within which the energy is consumed the bundled

retail sale of electric energy, unbundled local

distribution service, and unbundled retail sale of

electric energy and attendant facilities.

Title II: Repeal of PURPA Mandatory Purchase

Requirement 

  Directs that, with respect to new contracts, no

electric utility shall be required to enter into a new

contract or obligation to purchase or sell electricity

or capacity under the Public Utility Regulatory

Policies Act of 1978. 

  Preserves existing contract rights and remedies

under such Act.

Title III: Electric Reliability 

  Amends the Federal Power Act to provide for the

establishment and enforcement of mandatory

reliability standards to ensure the reliable operation of the bulk power system.

  Grants FERC jurisdiction over (1) the Electric

Reliability Organization, (2) all affiliated regional

reliability entities (entities to which authority has

been delegated to enforce compliance with reliability standards), (3) all system operators and all

users of the bulk power system for purposes of

approving and enforcing compliance with

standards in the United States. 

  Provides that, before establishment of the Electric

Reliability Organization, any person (including the

North American Electric Reliability Council and its

member Regional Reliability Councils) shall file a

proposed reliability standard, guidance, or practice which, subject to FERC approval, shall be

mandatory and enforceable.

Title IV: Repeal of the Public Utility Holding Company

Act of 1935 and Enactment of the Public Utility Holding

Company Act of 1999 

  Repeals the Public Utility Holding Company Act

of 1935 effective 1 year after enactment of this title.

  Prescribes procedural guidelines for (1) FERC

access to records of a public utility or natural gas

holding company, and (2) State access to records

of a public utility in a holding company system.

  Instructs FERC to promulgate a final rule to

exempt for such Federal access requirements any

holding company with respect to one or more (1)

qualifying facilities under PURPA, (2) exempt

wholesale generators, or (3) foreign utility companies. 

  Retains the jurisdiction of FERC and State commissions to determine whether a public utility

company or natural gas company may recover in

rates any costs of affiliate transactions; grants

FERC certain FPA enforcement powers; and transfers from the Securities and Exchange Commission

to FERC all books and records that relate primarily

to the functions vested in FERC by this Act.

Title V: Nuclear Decommissioning

 Permits a nuclear power facility licensee to petition

the Nuclear Regulatory Commission for a determination of whether (1) adequate amounts are

deposited in its nuclear decommissioning trust

fund, and (2) future funding for any nuclear power

plant is assured for any nuclear power plant

owned in whole or in part by such licensee.
Appendix D

Electric Power Industry

Statistics
Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 151

Appendix D

Electric Power Industry Statistics

The Energy Information Administration (EIA) collects

and disseminates electric power industry statistics, and

a summary of those statistics is provided in Table D1.

The following publications contain additional industry

data relevant to this report and are available from EIA’s

website at http://www.eia.doe.gov. The reports are

also available in hardcopy by contacting the National

Energy Information Center via telephone at 202-586-8800

or via Internet at infoctr@eia.doe.gov. Previous analysis

reports dealing with the restructuring of the electric

power industry are also attainable.

Carbon Dioxide Emissions from the Generation of

Electric Power in the United States

This report summarizes carbon dioxide emissions

produced by electricity generation in the United States.

Electric Power Annual, Volume I

This publication contains data on net generation; fossil

fuel consumption, stocks, receipts, and cost; generating

unit capability; retail sales of electricity and associated

revenue; and the average revenue per kilowatthour of

electricity sold.

Electric Power Annual, Volume II

This publication presents an overview of the electric

power industry in the United States and a summary of

industry statistics at national, regional, and State levels.

Electric Power Monthly

This report provides monthly statistics at the State,

Census division, and national levels for net generation,

fossil fuel consumption and stocks, quantity and quality

of fossil fuels, cost of fossil fuels, electricity sales,

revenue, and average revenue per kilowatthour of

electricity sold.

Electric Sales and Revenue

This publication provides information on electricity

sales, associated revenue, average revenue per kilowatthour sold, and number of consumers throughout the

United States. Data are presented at the national,

Census division, State, and electric utility levels.

Electric Trade in the United States

This report presents information on bulk power

transactions by investor-owned utilities, Federal and

other publicly owned utilities, and cooperative utilities.

Financial Statistics of Major U.S. Investor-Owned

Electric Utilities

This publication presents summary and detailed

financial accounting data on investor-owned electric

utilities.

Financial Statistics of Major U.S. Publicly Owned

Electric Utilities

This report presents summary financial data for the past

5 years and detailed current financial data on major

publicly owned electric utilities.

Inventory of Electric Utility Power Plants in the

United States

This report provides annual statistics on generating

units operated by electric utilities in the United States.

The publication also presents a 5-year outlook for

generating unit additions and retirements.

Inventory of Nonutility Power Plants in the

United States

This publication summarizes U.S. nonutility data with

detailed information on existing and planned net

summer capability, nameplate capacity, energy source

and prime mover, as well as information on facility

owner and facility locations.

The Restructuring of the Electric Power Industry % A

Capsule of Issues and Events

This brochure offers an overview of electric power

industry restructuring, including the major changes that

have already occurred, their causes, and currents events.

State Electricity Profiles

This report is designed to profile each State and the

District of Columbia regarding not only their current

restructuring activities but also their electricity

generation and concomitant statistics. Included are data
152 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

on a number of subject areas, including generating

capability, generation, revenues, fuel use, capacity factor

of nuclear plants, retail sales, and pollutant emissions.

U.S. Electric Utility Demand-Side Management

This publication presents comprehensive information on

electric power industry demand-side management

(DSM) activities in the United States at the national,

regional, and utility levels.

Table D1. Electric Power Industry Summary Statistics for the United States, 1998

Item 1998

Electric Power Industry1

 Generating Capability (megawatts)

2 .................................. 775,885

 Net Generation (million kilowatthours) ................................ 3,617,873

 Emissions (thousand short tons)3

 Sulfur Dioxide (SO2) ............................................... 13,083

 Nitrogen Oxides (NOX) ............................................. 7,902

 Carbon Dioxide (CO2)

4 ............................................. 2,455,267

Electric Utilities

 Generating Capability (megawatts)2,5,9 ................................ 686,692

 Coal ............................................................ 299,739

 Petroleum ....................................................... 62,959

 Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125,386

 Hydroelectric Pumped Storage ....................................... 18,898

 Nuclear ......................................................... 97,070

 Waste Heat ...................................................... 4,818

 Hydroelectric (conventional) ......................................... 75,525

 Other Renewable

 Geothermal ..................................................... 1,550

 Biomass6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 504

 Wind .......................................................... 9

 Photovoltaic ..................................................... 5

 Net Generation (million kilowatthours) 3,212,171

 Coal ............................................................ 1,807,480

 Petroleum7 ....................................................... 110,158

 Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 309,222

 Nuclear .......................................................... 673,702

 Hydroelectric Pumped Storage8 ....................................... -4,441

 Hydroelectric (conventional) .......................................... 308,844

 Other Renewable

 Geothermal ..................................................... 5,176

 Biomass6 ....................................................... 2,024

 Wind .......................................................... 3

 Photovoltaic ..................................................... 3

 Consumption

 Coal (million short tons) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 911

 Petroleum (million barrels)10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179

 Gas (billion cubic feet) .............................................. 3,258

 Stocks (Year End)

 Coal (million short tons) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

 Petroleum (million barrels)11 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

 Receipts

 Coal (million short tons) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 929

 Petroleum (million barrels)12 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165

 Gas (billion cubic feet)13 ............................................. 2,924

 Cost (cents per million Btu)14 ........................................

 Coal ............................................................ 125.2

 Petroleum15 ...................................................... 213.6

 Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238.1

 Sales To Ultimate Consumers (million kilowatthours) 3,239,818

 Residential ....................................................... 1,127,735

 Commercial ....................................................... 968,528

 Industrial ......................................................... 1,040,038

 Other16 .......................................................... 103,518

 Revenue From Ultimate Consumers (million dollars) 218,346

 Residential ....................................................... 93,164

 Commercial ...................................................... 71,769

 Industrial ......................................................... 46,550

 Other16 .......................................................... 6,863

 See footnotes at end of table.
Table D1. Electric Power Industry Summary Statistics for the United States, 1998

(Continued) 

Item 1998

Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update 153

 Average Revenue per Kilowatthour (cents) 6.74

 Residential ....................................................... 8.26

 Commercial ...................................................... 7.41

 Industrial ......................................................... 4.48

 Other16 .......................................................... 6.63

 Net Electric Plant Inc Fuel (million dollars)

 Major Investor Owned .............................................. 333,006

 Major Publicly Owned Generator/Nongenerator .......................... 69,725

 Emissions (thousand short tons)17

 Sulfur Dioxide (SO2) ................................................ 12,432

 Nitrogen Oxides (NOX) .............................................. 7,221

 Carbon Dioxide (CO2)............................................... 2,209,286

 Noncoincidental Summer Peak Load (megawatts) ...................... 669,069

 DSM Actual Peak Load Reductions (megawatts) ........................ 27,231

 DSM Energy Savings (million kilowatthours) ........................... 49,167

Nonutility Power Producers

 Installed Capacity (megawatts) ...................................... 98,085

 Coal18 ........................................................... 13,712

 Petroleum Only19 .................................................. 2,629

 Gas Only20 ....................................................... 37,530

 Petroleum/Natural Gas (combined) .................................... 23,105

 Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . --

 Hydroelectric (conventional) .......................................... 4,136

 Other Renewable

 Geothermal ..................................................... 1,449

 Biomass6 ....................................................... 10,374

 Wind .......................................................... 1,689

 Solar Thermal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 385

 Photovoltaic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . --

 Other21 .......................................................... 3,075

 Gross Generation (million kilowatthours).............................. 421,364

 Coal18 ........................................................... 70,369

 Petroleum19 ...................................................... 17,533

 Gas20 ........................................................... 247,613

 Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . --

 Hydroelectric (conventional) .......................................... 14,633

 Other Renewable

 Geothermal ..................................................... 9,882

 Biomass6 ....................................................... 53,682

 Wind .......................................................... 3,015

 Solar Thermal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 887

 Photovoltaic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . --

 Other21 ........................................................ 3,750

 Consumption22

 Coal (Thousand short tons) .......................................... 56,850

 Petroleum (Thousand barrels)23 ...................................... 58,745

 Natural Gas (Million cubic feet) ....................................... 2,666,430

 Other Gas (Million cubic feet)24 ....................................... 881,017

 Supply and Disposition (million kilowatthours)

 Gross Generation .................................................. 421,364

 Receipts25 ....................................................... 90,675

 Deliveries26 ....................................................... 275,260

 Facility Use ....................................................... 236,770

 Emissions (thousand short tons)27

 Sulfur Dioxide (SO2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 651

 Nitrogen Oxides (NOX) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 681

 Carbon Dioxide (CO2)............................................... 245,981

1 Electric utility and nonutility values (capability versus capacity, net versus gross generation, total emissions versus emissions for the

production of electricity) may not be summed directly.

2

 Data are based on the initial commercial operation year for the generator.

3

 In 1997, the useful utility thermal output produced additional emissions of 192 thousand short tons of sulfur dioxide, 66 thousand short

tons of nitrogen oxides, and 18,159 thousand short tons of carbon dioxide. In 1998, the useful utility thermal output produced additional

emissions of 231 thousand short tons of sulfur dioxide, 91 thousand short tons of nitrogen oxides, and 29,267 thousand short tons of

carbon dioxide. In 1997, the useful nonutility thermal output produced additional emissions of 775 thousand short tons of sulfur dioxide,

473 thousand short tons of nitrogen oxides, and 143,824 thousand short tons of carbon dioxide. In 1998, the useful nonutility thermal

output produced additional emissions of 756 thousand short tons of sulfur dioxide, 493 thousand short tons of nitrogen oxides, and

185,084 thousand short tons of carbon dioxide.

4

 The report, Carbon Dioxide Emissions from the Generation of Electric Power in the United States, presented carbon dioxide emissions

of 2,359,853 thousand short tons in 1997 and 2,447,457 thousand short tons in 1998. The nonutility data were revised since the October

15, 1999 release of that report.
Table D1. Electric Power Industry Summary Statistics for the United States, 1998

(Continued) 

Item 1998

154 Energy Information Administration/ The Changing Structure of the Electric Power Industry 2000: An Update

5

 Net summer capability based on primary energy source. Waste gases and waste steam are included in the original primary energy

source (i.e., coal, petroleum, or gas). Historical data have been revised to reflect this change.

6

 Includes wood, wood waste, peat, wood liquors, railroad ties, pitch, wood sludge, municipal solid waste, agricultural byproducts, straw,

tires, landfill gases, and fish oils.

7

 Includes petroleum coke.

8

 Represents total pumped storage facility production minus energy used for pumping. Negative generation denotes that electric power

consumed for plant use exceeds gross generation.

9

 Includes 216 megawatts multi-fueled capacity and 13 megawatts fueled by hot nitrogen.

10 Does not include petroleum coke consumption of 1,400 thousand short tons in 1997 and 1,769 thousand short tons in 1998. 11 Does not include petroleum coke stocks of 469 thousand short tons at year end 1997 and 559 thousand short tons at year end 1998. 12 Does not include petroleum coke receipts of 2,192 thousand short tons in 1997 and 3,217 thousand short tons in 1998. 13 Includes small amounts of coke-oven, refinery, blast furnance, and landfill gas. 14 Average cost of fuel delivered to electric generating plants with a total steam-electric nameplate capacity of 50 or more megawatts;

average cost values are weighted by Btu.

15 Does not include petroleum coke cost of 91.2 cents per million Btu in 1997 and 71.2 cents per million Btu in 1998. 16 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental

sales.

17 Includes only those power plants with a fossil-fueled steam-electric nameplate capacity (existing or planned) of 10 or more

megawatts. As of 1998, emission factors for the calculation of carbon dioxide emissions have been changed. Historical data were revised

to reflect that change. 

18 Includes coal, anthracite culm, coke breeze, fine coal, waste coal, bituminous gob, and lignite waste. 19 Includes petroleum, petroleum coke, diesel, kerosene, liquid butane, liquid propane, oil waste, and tar oil. 20 Includes natural gas, waste heat, waste gas, butane, methane, propane, and other gas. 21 Includes hydrogen, sulfur, batteries, chemicals, and purchased steam. 22 Includes all combustible fuels burned at generating facilities (not just for the production of electricity). 23 Does not include petroleum coke consumption of 4,364 thousand short tons for 1997 and 4,470 thousand short tons for 1998. 24 Includes butane, methane, propane, digester gas, and other gas. 25 Includes purchases, interchanges, and exchanges of electric energy with utilities and other nonutilities. 26 Includes sales, interchanges, and exchanges of electric energy with utilities and other nonutilities. The disparity in these data and

data reported on other EIA surveys occurs due to differences in the respondent universe. The Form EIA-860B and the Form EIA-867

are filed by nonutilities reporting the energy delivered, while other data sources are filed by electric utilities reporting energy received.

Differences in terminology and accounting procedures contribute to the disparity. In addition, since the frame for the Form EIA-860B and

the Form EIA-867 is derived from utility surveys, the Form EIA-860B and the Form EIA-867 universes lag 1 year.

27 In 1998, emission factors for the calculation of carbon dioxide and the reductions from nitrogen oxides and sulfur dioxide have been

changed. Historical data were revised to reflect that change. 

R = Revised data.

Notes:  Data previously published have been reclassified by energy source and have been changed to reflect these changes.  Data

for nonutiliity power producers and emissions are preliminary for 1998; other data in this table are final.  Totals may not equal sum of

components because of independent rounding.  Percent change is calculated before rounding. 

Sources: Energy Information Administration, Form EIA-412, “Annual Report of Public Electric Utilities”; Form EIA-759, “Monthly Power

Plant Report”; Form EIA-860, “Annual Electric Generator Report” for 1997; Form EIA-860A, “Annual Electric Generator Report - Utility”

for 1998; Form EIA-861, “Annual Electric Utility Report”; Form EIA-767, “Steam-Electric Plant Operation and Design Report”; Form EIA860B, “Annual Electric Generator Report- Nonutility” for 1998 and Form EIA-867, “Annual Nonutility Power Producer Report” for 1997;

Federal Energy Regulatory Commission (FERC) Form 1, “Annual Report of Major Electric Utilities, Licensees, and Others” as edited

by Navigant Consulting, Inc.; FERC Form 423, “Monthly Report of Cost and Quality of Fuels for Electric Plants”; Form EIA-411,

“Coordinated Bulk Power Supply Programs”; Department of Energy, Office of Emergency Policy, Form OE-411, “Coordinated Bulk Power

Supply Program.”