DOE/EIA-0562(96)

Distribution Category UC-950

The Changing Structure of the

Electric Power Industry: An Update

December 1996

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: An Update

Contacts

This report was prepared by the staff of the Coal and 1180 or via Internet at bobrien@eia.doe.gov. Specific

Electric Analysis Branch, Analysis and Systems Division, questions regarding the preparation and content of the

Office of Coal, Nuclear, Electric and Alternate Fuels. report should be directed to Rebecca A. McNerney, project

General information regarding this publication may be manager of the publication, by phone on 202/426-1251 or

obtained from Robert M. Schnapp, Director, Analysis and via Internet at rmcnerne@eia.doe.gov. Questions

Systems Division, by phone on 202/426-1211 or via regarding specific chapters of the report should be

Internet at rschnapp@eia.doe.gov, or Betsy O'Brien, Chief, directed as follows:

Coal and Electric Analysis Branch, by phone on 202/426-

Phone Internet

Chapter 1: Rebecca A. McNerney (202) 426-1251 rmcnerne@eia.doe.gov

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

Chapter 3: Larry R. Spancake (202) 426-1131 lspancak@eia.doe.gov

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

Chapter 5: Larry R. Spancake (202) 426-1131 lspancak@eia.doe.gov

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

Chapter 7: Dr. Suraj P. Kanhouwa (202) 426-1257 skanhouw@eia.doe.gov

Chapter 8: Dr. Suraj P. Kanhouwa (202) 426-1257 skanhouw@eia.doe.gov

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

Preface

Section 205(a)(2) of the Department of Energy Organi- The legislation that created the EIA vested the organizazation Act of 1977 (Public Law 95-91) requires the tion with an element of statutory independence. The EIA

Administrator of the Energy Information Administration does not take positions on policy questions. The EIA's

(EIA) to carry out a central, comprehensive, and unified responsibility is to provide timely, high-quality

energy data information program that will collect, information and to perform objective, credible analyses in

evaluate, assemble, analyze, and disseminate data and support of deliberations by both public and private

information relevant to energy resources, reserves, decisionmakers. Accordingly, this report does not purport

production, demand, technology, and related economic to represent the policy positions of the U.S. Department of

and statistical information. To assist in meeting these Energy or the Administration.

responsibilities in the area of electric power, EIA has

prepared this report, The Changing Structure of the Electric This report can be accessed and downloaded as a Portable

Power Industry: An Update. The purpose of this report is to Document Format (PDF) file from EIA’s World Wide Web

provide a comprehensive overview of the structure of the site by connecting your Web browser (i.e., Netscape, MS

U.S. electric power industry over the past 10 years, with Internet Explorer, etc.) to EIA’s Home Page at

emphasis on the major changes that have occurred, their http://www.eia.doe.gov. Once connected, click on

causes, and their effects. It is intended for a wide “Electric” to go to the “Electric Page.” Then, move to the

audience, including Congress, Federal and State agencies, Publications menu and click on the publication title to

the electric power industry, and the general public. begin the download process.
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update v

Contents

Page

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

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

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

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

3. Electric Power Generation Components .............................................................. 9

Utilities ......................................................................................... 9

Nonutilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Recent Expansion of Utilities and Nonutilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

The Interconnected Networks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

4. Federal Legislative Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

The Public Utility Holding Company Act of 1935 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

The Public Utility Regulatory Policies Act of 1978 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

The Energy Policy Act of 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Part II: The U.S. Electric Power Industry in Transition to Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

5. Factors Underlying the Restructuring of the Electric Power Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Price Differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Technological Advances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

6. Federal Legislative Initiatives for Change: The Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

The Current Debate Over PUHCA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

The Current Debate Over PURPA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Proposed Comprehensive Energy Restructuring Bills . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

7. Evolving Regulatory Reform: The Federal and State Role in Promoting Competition . . . . . . . . . . . . . . . . . . . 51

FERC’s Role in Promoting Competition in Wholesale Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Role of States in Promoting Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

8. Stranded Costs in Electricity Deregulation: An Overview of Potential Mitigation Strategies . . . . . . . . . . . . 77

Stranded Costs: Emergence and Conceptualization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Magnitude of Potential Stranded Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

Mitigation Requirements in Recovery of Stranded Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Mitigation Strategies To Address Stranded Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Results of Mitigation Strategies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

Concluding Remarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84

9. Transitional Developments and Strategies: The Industry Prepares for Competition . . . . . . . . . . . . . . . . . . . . 85

Investor-Owned Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

Publicly Owned Utilities and Cooperatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
vi Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Contents (Continued)

Power Marketers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Spot Markets and New Trading Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Independent System Operators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

Appendices

A. History of the U.S. Electric Power Industry, 1882-1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

B. Historical Chronology of Energy-Related Milestones, 1800-1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113

C. Statistical Tables for the Electric Power Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

D. Brief Characteristics of the Oak Ridge Financial Model (ORFIN) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

E. Stranded Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

F. Selected Provisions of the Energy Policy Act of 1992 (Public Law 102-486), Title VII—Electricity . . . . . . . . . . 159

G. Selected Provisions of the Federal Power Act Referenced in the FERC Mega-NOPR . . . . . . . . . . . . . . . . . . . . . 175
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update vii

Tables

1. Number of Electric Utilities by Class of Ownership and NERC Region, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

2. Relative Size of Registered Holding Companies as of January 1, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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

1995-2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

4. Proposed Legislation Influencing the Restructuring of the Electric Power Industry Introduced During the

104th Congress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

5. Status of Electric Industry Restructuring by State, as of June 30, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

6. Average and Marginal Cost of Electricity Production by Census Division, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . 80

7. Regional Distribution of Stranded Costs by Census Division, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

8. Mergers and Acquisitions of Investor-Owned Utilities, 1986-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

9. Number of Nonutility Subsidiary Companies Owned by Electric Utility Holding Companies, 1986-1994 . . . 93

10. Investments in Exempt Wholesale Generators and Foreign Utilities in 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

11. NYMEX Futures Contract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

B1. Historical Chronology of Energy-Related Milestones, 1800-1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

C1. Nameplate Capacity at Utilities by Class of Ownership, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

C2. Nameplate Capacity at Nonutilities by Type of Facility and Major Industry Group, 1995 . . . . . . . . . . . . . . . . . 127

C3. Planned Nameplate Capacity Additions in 1995 by Prime Mover and Type of Facility for the Electric 

Power Industry, 1996-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

C4. Capacity and Generation Statistics for the Electric Power Industry, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

C5. Electric Power Industry Generation by Census Division and State, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

C6. Statistics of the Utility Sector of the Electric Power Industry, 1970-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

C7. Statistics of the Nonutility Sector of the Electric Power Industry, 1970-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132

C8. Average Nameplate Capacity and Number of Utility-Operated Coal-Fired Steam Turbine Units by 

Historical or Planned Year of Commercial Operation, 1970-2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

C9. Average Nameplate Capacity and Number of Nonutility-Owned Units by Selected Prime Mover and

Historical or Planned Year that Electricity First Generated, 1970-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134

D1. Key Inputs to ORFIN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

E1. Alternative Ways to Compute Stranded Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144

E2. Who Bears Transition Costs? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151

E3. Potential Effects of Different Strategies on Base-Case Utility Transition Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . 152

E4. Base Case Utility Projections (No Wheeling) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155

E5. Base Case Utility Projections (With Wheeling) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156

E6. Performance Benchmark for Utility Cost Variables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157

Figures

1. North American Electric Reliability Council Regions for the Contiguous United States and Alaska . . . . . . . . . 11

2. Electric Utility Generation and Retail Sales by Ownership Category, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

3. Shares of Nonutility Nameplate Capacity by Major Industry Group, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

4. Utility and Nonutility Nameplate Capacity, 1985-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

5. Utility and Nonutility Net Additions to Nameplate Capacity, 1986-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

6. Utility and Nonutility Planned Additions to Nameplate Capacity, 1996-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

7. Utility and Nonutility Generation and Shares by Class, 1985 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

8. Regions and Interconnections of the North American Electric Reliability Council in the Contiguous

United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

9. Electric Utility Wholesale Power Purchases by Ownership Type, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

10. U.S. International Electricity Trade, 1985-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

11. Average Revenue from Electricity Sales to All Retail Consumers by State, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . 36

12. Average Revenue from Electricity Sales to Industrial Consumers by State, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . 37

13. Relative Average Revenue of Electricity Sales: Ratio of Industrial Consumers to All Consumers, 1960-1995 . 38

14. Estimates of Stranded Costs by Census Division, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

15. Allocation of Revenue Dollars from Electric Operations for Major U.S. Investor-Owned Utilities, 1995 . . . . . . 85
viii Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Figures (Continued)

16. Allocation of Electric Operation and Maintenance Expenses of Major U.S. Investor-Owned Utilities, 1995 . . . 86

17. Trends in Operation and Maintenance Expenses of Investor-Owned Utilities, 1986-1995 . . . . . . . . . . . . . . . . . . 87

18. Number of Investor-Owned Electric Utilities, 1986-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

19. Comparison of Costs Before and After Merger of Iowa Power and Iowa Public Service . . . . . . . . . . . . . . . . . . . 92

20. Comparison of Costs Before and After Merger of Kansas P&L and Kansas G&E . . . . . . . . . . . . . . . . . . . . . . . . . . 92

21. Allocation of Revenue Dollars from Electric Operations for Publicly Owned Generator Utilities, 1994 . . . . . . 95

22. Allocation of Electric Operation and Maintenance Expenses for Publicly Owned Generator Utilities, 1994 . . 96

23. Operation and Maintenance Expenses for Publicly Owned Electric Utilities, 1989-1994 . . . . . . . . . . . . . . . . . . . 96

24. Payoff Diagram for Long and Short Futures Positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

D1. Schematic Representation Defining ORFIN Assessment Framework . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update ix

 An electric utility is a corporation, person, agency, authority, or other legal entity or instrumentality that owns and/or operates facilities in the United 1

States, its territories, or Puerto Rico, for the generation, transmission, distribution, or sale of electric energy primarily for use by the public.

 A vertically integrated utility is one which engages in generation, transmission, and distribution operations. 2

 These numbers are drawn from the research undertaken by Dr. Jeff Fang of the National Renewable Energy Laboratory with funding provided by the 3

Energy Information Administration.

 Rate of return is the ratio of net operating income earned by a utility, calculated as a percentage of its rate base. 4

Executive Summary

Electric utilities —one of the largest remaining regulated reliably, and efficiently. Utility consumers have seen 1

industries in the United States—are in the process of differences in prices in neighboring States (Figure ES1),

transition to a competitive market. Traditionally vertically and those States with higher electricity rates like

integrated, the industry will in all probability be segmen- California and those in the Northeast are promoting 2

ted at least functionally into its three component parts: competition in the hope of making lower rates available.

generation, transmission, and distribution. The proposals In fact, California, New York, and most of the New

and issues are being addressed in Federal and State legis- England States are opening their retail electric power

lation and are being debated in State regulatory hearings. markets to competition in 1998. Independent power

Change is occurring through the issuance by the Federal and increased profitability. Regulators are experimenting

Energy Regulatory Commission (FERC) of Orders 888 and with alternative forms of regulation (e.g., performance889 (dated April 24, 1996) to encourage wholesale based rates) because some groups believe that the

competition. Order 888 addresses the issues of open access traditional practice of regulating a utility's rate of return

to the transmission network and stranded costs. Order 889 does not contain sufficient incentives to encourage

requires utilities to establish electronic systems to share efficient utility operations. And utilities are dissatisfied

information about available transmission capacity. In with legislation that has given a competitive advantage to

addition, as of June 30, 1996, 44 States and the District of nonutility electricity producers and limits holding

Columbia (more than 88 percent of the Nation's company activities. 

regulatory commissions) have started activities related to

retail competition in one form or another. Issues such as With competition on the horizon, investor-owned utilities 3

recovery of stranded costs, divestiture of transmission (IOUs) are reducing staff and reorganizing their

assets, increased mergers, renewable energy incentives, companies to lower costs. IOUs have taken advantage of

energy efficiency investments, reliability, and the timing lower fuel prices by modifying their fuel acquisition

of retail competition are critical due to the degree of procedures (such as buying out older, more expensive fuel

importance electricity holds in this country's economic contracts and purchasing less expensive coal in the spot

and social well-being. Legislative proposals on electric market), which has helped decrease their real operation

power restructuring have been introduced into the U.S. and maintenance costs (in 1995 dollars) from about 4.5

House of Representatives and the U.S. Senate. cents per kilowatthour in 1986 to 3.5 cents per

The electric power industry has once before, during the purchases over the past decade has hindered efforts to

late 1930s and early 1940s, undergone major realignment. lower costs for some utilities. On the other hand, nonfuel

However, the situation was very different then because it operation and maintenance costs have remained stable,

was forced by Federal law in order to bring an end to the indicating that some progress in cost reduction has been

financial exploitation of utilities and ratepayers by large achieved, but also indicating that more may be needed. 

holding companies. The current process for change is

driven by extensive discussions and hearings at the Some of the largest IOUs are expanding their business

Federal and State levels. For example, many consumers, investments in energy service companies; oil and gas

primarily industrial, express the desire to choose the exploration, development, and production; foreign

electricity supplier that meets their needs economically, ventures; and, more recently, telecommunications

producers look to an unconstrained market for expansion

4

kilowatthour in 1995 (Figure ES2). An increase in power
x Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

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

December 1996), Table 7.

Figure ES1. Average Revenue from Electricity Sales to All Retail Consumers by State, 1995

(Cents per Kilowatthour)

ventures. Electric utilities are also planning to improve cooperatives may find that they need to lower costs. Many

their competitive positions through mergers and acquisi- of them are now reacting to competitive pressures by

tions. In 1995, 13 investor-owned electric utilities merged reducing staff and engaging in other cost-cutting acor had mergers pending with other utilities in the indus- tivities. Although a few publicly owned utilities have

try, as compared with 1 in 1994 and 4 in 1993. Company recently announced merger plans, there is not a significant

executives claim that such mergers result in cost savings. merger trend when compared to IOUs. Publicly owned

However, comparing costs before and after two of the utilities can capture some of the same efficiencies of a

mergers in 1992 indicates that savings do not always merger by sharing resources and forming mutual aid

occur. programs. Objections to merger plans of IOUs have been

Publicly owned utilities and rural electric cooperatives mergers result in unnecessary consolidation of generation

will also be affected by industry restructuring. In general, capacity and create excess market power.

they have lower operating costs than IOUs, and most of

them can sell electricity at a competitive price. However, In addition to the activities of electric utilities, other

with increased competition from IOUs and electricity important events are taking place in the industry. Power

marketing companies, publicly owned utilities and marketers— companies that buy and then resell electric

raised by some publicly owned utilities who contend that
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

1

2

3

4

5

Fuel Purchases

Nonfuel O&M

Total 

Operation & 

Maintenance 

Costs

Power Purchases

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

 The low estimates of stranded costs are attributable to the American Public Power Association. The high estimates come from many sources. See 5

Chapter 8 for further information.

 Oak Ridge National Laboratory, ORFIN: An Electric Utility Financial and Production Simulator, ORNL/CON-431 (Oak Ridge, TN, March 1996). 6

Source: Energy Information Administration, Financial

Statistics of Major U.S. Investor-Owned Electric Utilities 1995,

DOE/EIA-0437(95)/1 (Washington, DC, December 1996), and

previous issues.

Figure ES2. Operation and Maintenance (O&M)

Costs of Major Investor-Owned

Utilities, 1986-1995

 and are likely to result in reductions of 25 percent or more

energy and transmission and other services from in an at-risk utility's stranded costs. In Order 888, FERC

traditional utilities—are emerging as new players in the stated that recovery of stranded costs should be allowed

industry. Although relatively small in terms of volume of because it is critical to the successful transition to a comsales (i.e., less than 5 percent of wholesale electricity sales petitive wholesale environment with open access to transin 1995), power marketers are a growing segment of the mission capacity. The stranded costs will be recovered

industry. Stimulating this growth, electricity spot markets from departing wholesale customers.

are operating at several sites across the country. Power

marketers and some electric utilities are using spot mar- At this time, the outcome of the reforms being considered

kets as an alternative source of wholesale power. The cannot be definitively predicted, nor can all of the impacts

California-Oregon Border (COB) and the Palo Verde be foreseen. It is the intention of this report to describe the

switchyard are two of the largest electricity trading forces motivating the move to competition, the relevant

centers at this time. Electricity futures contracts, new laws and regulations, the trends and current developfinancial instruments that help traders manage the risks in ments, the roles of industry players and regulators, and

electricity trading, were started at COB and Palo Verde in the concerns of consumers. Subsequent reports by the

March 1996. Finally, the concept of an independent sys- Energy Information Administration will give updates on

tem operator (ISO), an entity that will independently the status of proposed reforms and, where possible, will

manage a transmission grid owned by one or more electric analyze the effects of the transition on such matters as

generation companies, is growing in importance. ISOs are electricity demand, pricing, reliability, social and environconsidered by most to be a key component for achieving mental programs, bulk power markets, technological

effective wholesale competition. The California Public advances, issues and trends in fuel use, and stranded cost

Utility Commission’s proposal to transfer operational recovery methods in the States.

control (but not ownership) of certain transmission

facilities to an ISO is perhaps the most publicized plan.

Proposals to start ISOs are also being discussed in New

York, Wisconsin, Massachusetts, Texas, and other States.

Stranded costs are a major concern to many industry

groups, especially to the electric utilities. These are costs

that have been prudently incurred by utilities to serve

their consumers but cannot be recovered if the consumers

choose other electricity suppliers. One study has estimated current stranded assets at $88 billion, and estimates

of projected stranded costs range from a low of $10 to $20

billion to a high of $500 billion. Utilities are looking for 5

ways to mitigate stranded costs, and regulators are

evaluating who should pay them. The strategies being

considered would allocate the costs to ratepayers, shareholders, wheeling customers, taxpayers, and/or nonutility

suppliers. Ideas such as delaying the start of retail competition, charging exit fees to departing customers, reducing administrative and general costs, and discounting

qualifying facility energy payments are being considered

6
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 1

 “The critical and—if properly defined—all-embracing characteristic of natural monopoly is an inherent tendency to decreasing costs over the entire 1

extent of the market. This is so only when the economies achievable by a larger output are internal to the individual firm—if, that is to say, it is only as more

output is concentrated in a single supplier that unit costs will decline.” Alfred E. Kahn, The Economics of Regulation, Principles and Institutions, Vol. 2

(Cambridge, MA: The MIT Press, 1988), p. 119.

1. Introduction

The U. S. electric power industry today is on the road to Commission (FERC) issued rules for implementing open

restructuring—a road heretofore uncharted. While paral- access to the transmission network and recovering

lels can be drawn from similar journeys taken by the stranded costs. The State public utility commissions are

airline industry, the telecommunications industry, and, actively studying retail competition, and some have almost recently, the natural gas industry, the electric power ready introduced pilot programs or have drawn up plans

industry has its own unique set of critical issues that must for restructuring. An electricity futures market and newly

be resolved along the way. The transition will be from a formed entities, such as power marketers and brokers and

structure based on a vertically integrated and regulated independent system operators, are emerging and are

monopoly to one equipped to function successfully in a taking their respective places in the dynamic composition

competitive market. of the industry. In relation to the length of time that the

 industry has existed and that utilities have been vertically

The long-standing traditional structure of the electric integrated, changes are happening almost overnight.

power industry is the result of a complex web of events

that have been unfolding for over 100 years. Some of The purpose of this report, which is intended for both lay

these events had far-reaching and widely publicized and technical readers, is twofold. First, it is a basic refereffects (e.g., Franklin D. Roosevelt's New Deal in the ence document that provides a comprehensive delineation

1930s, the Northeast Blackout of 1965, the Arab Oil of the electric power industry and its traditional structure,

Embargo of 1973, and the Three Mile Island incident in which has been based upon its monopoly status. Second,

1979). Other major events took the form of legislation (e.g. it describes the industry's transition to a competitive

the Public Utility Holding Company Act of 1935 environment by providing a descriptive analysis of the

[PUHCA], the Public Utility Regulatory Policies Act of factors that have contributed to the interest in a

1978 [PURPA], and the Energy Policy Act of 1992 competitive market, proposed legislative and regulatory

[EPACT]). Still other events had effects that are less actions, and the steps being taken by the various

obvious in comparison (e.g., the appearance of tech- components of the industry to meet the challenges of

nologies such as transformers and steam and gas turbines, adapting to and prevailing in a competitive environment.

the invention of home appliances, the man-made fission In order to facilitate the presentation, the report is divided

of uranium), and it is likely that their significance in the into two parts.

history of the industry has been obscured by the passage

of time. Nevertheless, they, too, hold a place in the Part I provides a historical overview of the electric power

underpinnings of today's electric industry structure. industry—a requisite piece to the changing structure

The old school of thought that considered utility power industry can be fully comprehended, it is necessary to

generation, transmission, and distribution a “natural mo- understand the conventional roles of the components of

nopoly” has given way to a general consensus that the electricity supply and factors that have affected them from 1

generation segment of power supply in today's environ- the beginning, including legislative and regulatory manment would be more efficient and economical if left to the dates, advancing technologies, and fluctuating economic

forces of an open market. The era of competition in the conditions. To that end, the overview section presents an

electric industry is upon us. The groundwork was laid, al- abridged version of the industry's history, touching on the

beit unintentionally, by the passage of PURPA, which events that have had the most profound effect on its

opened wholesale markets to nonutility producers of elec- structure. Also included is an in-depth look at the intricity in 1978, and EPACT, which expanded those mar- dustry's current structure and its generating, transmitting,

kets in 1992. In 1996, the Federal Energy Regulatory and distributing components. The substantially involved

puzzle. Before the transitional state of the current
2 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

subject of utility and nonutility organizational entities and customers but which cannot be recovered if the customers

their roles and relationships is examined in detail to choose other electricity suppliers—are examined.

provide an essential basic understanding of the supply Strategies to recover such costs are discussed, along with

component terms used throughout this report. Major the question of who will bear the costs. In addition, Part

legislation that has had the most profound impact on the II presents a detailed discussion of industry plans and

structure of the industry over the years is discussed, and developments that are emerging as a direct result of the

the discussion is accompanied by a table summarizing move toward competition, including strategies to lower

each law’s requirements along with additional laws that costs and other actions planned or already taken by major

have had significant effects on power suppliers. The investor-owned utilities to prepare for competition.

entirety of Part I was designed to be a convenient Likewise, the tactics of public utilities and cooperative

handbook that can be continually referenced to answer utilities are examined. 

questions concerning the fundamentals of the electric

power industry. This report also updates the statistics given in its

Part II addresses the current restructuring issues and Industry 1970-1991. That report, published in March 1993,

events. It outlines the forces behind the drive to portrayed the evolving roles of electric utilities and

restructure. The legislative proposals for reform and nonutilities and the corresponding data regarding the

restructuring that have been introduced into the U.S. changing patterns of electricity generation and capacity

Congress are cited and summarized, and the Federal and for both. Other trends were graphically illustrated and

State roles in promoting competition through regulatory accompanied by an interpretive analysis. Many of those

reform are described. The issue of stranded costs—that is, statistics are updated in Chapter 3, and additional data

the costs utilities have prudently incurred to serve their updates are presented in Appendix C.

predecessor, The Changing Structure of the Electric Power
Part I:

The U.S. Electric Power Industry

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

 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

Encyclopedia Americana, International Edition, Vol. 22 (New York, NY: Americana Corporation, 1977), p. 769. 5

Photo Unavailable for electronic document

Meter setter of the late 1800s makes his rounds. Photograph

courtesy of the Baltimore Gas and Electric Company.

2. A Brief Historical Overview 

of the Electric Power Industry

At the turn of the century, vertically integrated electric 2

utilities produced approximately two-fifths of the Nation's

electricity. At the 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 invention of the electric motor came the

inevitable use of more and 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.”3

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, trans- flaw in this type of regulation and promoting the push for

mission, and distribution was a natural monopoly. its demise.) 

Because monopolies in the United States were outlawed

by the Sherman Antitrust Act, regulation of the utilities Electric utility holding companies were forming and 4

was a necessity. In addition to its intrinsic design to expanding during this period, and by the 1920s they

protect consumers, regulation generally provided relia- controlled much of the industry. At their peak in the late

bility and a fair rate of return to the utility. The result was 1920s, the 16 largest electric power holding companies

traditional rate base regulation. (This form of rate setting controlled more than 75 percent of all U.S. generation.

has been blamed by some groups for removing the Originally formed to reap the benefits (mostly of a

incentive for utilities to achieve maximum efficiency in financial nature) of centralized ownership of a multitude

operations and planning, thereby exhibiting the major of subsidiaries, these unregulated holding companies

5
6 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 Energy Information Administration, Annual Outlook for U.S. Electric Power 1985, DOE/EIA-0474(85) (Washington, DC, August 1985), p. 3. 6

Ibid., p. 4. 7

 Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970 (Washington, DC, September 1973), pp. 2, 24. 8

Phot Unavailable for electronic document.

Electrically powered wagon used to promote the use of electric appliances, 1917. Photograph courtesy of the Baltimore Gas and

Electric Company.

were in a position to abuse their power over their sub contributed only 6 percent. In the following decade,

sidiaries. Sometimes, the result was increased costs paid President Franklin D. Roosevelt implemented a New Deal

by consumers of electricity. Because the States could not plan to build four hydroelectric power projects to be

regulate an interstate holding company, it became ap- owned and operated by the Federal Government.

parent that the Federal Government would have to step Roosevelt was able to get public power “on its feet.” In

in. After several large holding company systems col- 1937, the development of Federal power marketing

lapsed, an investigation by the Federal Trade Commission administrations began. Federal electricity generation

was ordered, leading eventually to the passage of the steadily expanded, providing less expensive electricity to

Public Utility Holding Company Act of 1935 (PUHCA). municipal and cooperative utilities. By 1940, Federal

Under the provisions of the Act, holding companies be- power pricing policy was set; all Federal power was

came regulated by the Securities and Exchange Com- marketed at the lowest possible price while still covering

mission. Utilities, which were involved in interstate costs. From 1933 to 1941, half of all new capacity was

wholesale marketing or transmission of electric power, be- provided by Federal and other public power installations.

came regulated by the Federal Power Commission (FPC). By the end of 1941, public power contributed 12 percent

In October 1977, the FPC became the Federal Energy of total utility generation, and Federal power alone

Regulatory Commission (FERC). contributed almost 7 percent. Even during the

By 1921, privately owned utilities were providing 94 Federal power continued to grow as earlier projects came

percent of total generation, and publicly owned utilities on line.

6

7

8

Eisenhower Administration's policy of “no new starts,”
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 7

 The Rural Electrification Administration has been replaced by the Rural Utilities Service, whose mission is to improve the quality of life in rural America 9

by administering its Electrification, Telecommunications, and Water and Waste Disposal Programs.

 The Federal Government moved quickly in the mid-1930s to, where opportunities appeared, produce and distribute less expensive federally produced 10

electricity to preference customers.

 Energy Information Administration, Annual Outlook for U.S. Electric Power 1985, DOE/EIA-0474(85) (Washington, DC, August 1985), p. 4. 11

 Energy Information Administration, Annual Outlook for U.S. Electric Power 1985, DOE/EIA-0474(85) (Washington, DC, August 1985), p. 6. 12

Photo unavailable for electronic document.

Chief Joseph Dam on the Columbia River, Washington, is a Bonneville Power Administration hydroelectric dam. U.S. Department of

Energy photograph.

In the mid-1930s, many homes, farms, and ranches in State and Federal Power Commission regulation. As a

rural areas were still without lights, indoor bathrooms, result, by 1941 the proportion of farm homes electrified

refrigerators, or running water. It was too expensive for rose to 35 percent, more than three times that of 1932.

the investor-owned utilities that served the cities to stretch

their lines into the countryside, so many areas remained For decades, utilities were able to meet increasing demand

without access to electric power. The Federal Government at decreasing prices. Economies of scale were achieved

encouraged the growth of rural electricity service by through capacity additions, technological advances, and

subsidizing the formation of rural electric cooperatives. declining costs, even during periods when the economy

The Rural Electrification Act of 1936 established the Rural was suffering. Of course, the monopolistic environment

Electrification Administration (REA) to provide loans and in which they operated left them virtually unhindered by 9

assistance to organizations providing electricity to rural the worries that would have been created by competitors.

areas and towns with populations under 2,500. REAbacked cooperatives enjoyed Federal power preferences This overall trend continued until the late 1960s, when the 10

plus lower property assessments, exemptions from electric utility industry saw decreasing unit costs and

Federal and State income taxes, and exemption from rapid growth give way to increasing unit costs and slower

11

12
8 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 Energy Information Administration, Annual Outlook for U.S. Electric Power 1985, DOE/EIA-0474(85) (Washington, DC, August 1985), p. 7. 13

 A nonutility is a corporation, person, agency, authority, or other legal entity or instrumentality that owns electric generating capacity and is not an 14

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.

growth. Over a relatively short time, a number of events some soon found that buying generation from a quali- 13

took place which contributed to the unprecedented fying facility (QF) had certain advantages over adding to

reversal in the growth and well-being of the industry: the their own capacity, especially because of the increasing

Northeast Blackout of 1965 raised pressing concerns about uncertainty of recovering capital costs. The growth of

reliability; the passage of the Clean Air Act of 1970 and its nonutilities was further advanced by the Energy Policy

amendments in 1977 required utilities to reduce pollutant Act of 1992 (EPACT). EPACT expanded nonutility

emissions; the Arab Oil Embargo of 1973-74 resulted in markets by creating a new category of power producers,

burdensome increases in fossil-fuel prices; the accident at exempt wholesale generators (EWGs), which are exempt

Three Mile Island in 1979 led to higher costs, regulatory from PUHCA's corporate and geographic restrictions.

delays, and greater uncertainty in the nuclear industry; Like QFs, EWGs are wholesale producers that do not sell

and inflation in general caused, among other problems, retail and do not own transmission facilities. Moreover,

interest rates to more than triple. unlike the nonutilities qualified under PURPA, EWGs are

While the industry was attempting to recover from this utilities are not required to buy their power. (For a more

onslaught of damaging events, Congress designed legis- detailed description of the purpose and effects of PUHCA,

lation that would reduce U.S. dependence on foreign oil, PURPA, and EPACT, see Chapter 4 of this report.)

develop renewable and alternative energy sources, sustain

economic growth, and encourage the efficient use of fossil A more detailed account of the industry’s history is

fuels. One result was the passage of the Public Utility provided in Appendix A, “History of the U.S. Electric

Regulatory Policies Act of 1978 (PURPA). PURPA became Power Industry, 1882-1991.” Appendix B, “Historical

a catalyst for competition in the electricity supply indus- Chronology of Energy-Related Milestones, 1800-1994,”

try, because it allowed nonutility facilities that met cer- lists the major technological and institutional events in the 14

tain ownership, operating, and efficiency criteria estab- development of the U.S. electric power industry. The

lished by FERC to enter the wholesale market. Utilities following chapter describes the organizational cominitially did not welcome this forced competition, but ponents of today’s electric power industry.

not regulated and may charge market-based rates, and
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 9

More specifically, public utilities are defined as enterprises that provide essential public services, such as electric, gas, telephone, water, and sewer, 15

under legally established monopoly conditions, whereas publicly owned electric utilities include only those utilities operated by municipalities and State and

Federal power agencies. Privately owned (or investor-owned) electric utilities are regulated and produce a return for investors (see inset).

Public Law 104-58, The Alaska Power Administration Asset Sale and Termination Act, passed on November 28, 1995, authorizes and directs the 16

Secretary of Energy to sell the Alaska Power Administration. The Alaska PMA comprises the Eklutna Hydroelectric Project and the Snettisham Hydroelectric

Project. The former is to be sold before December 31, 1997, and the latter by August 1998. 

3. Electric Power Generation Components

U.S. electric power generators consist of two broad larger utilities. This transmission network permits eleccategories of energy producers—utilities and nonutilities. tricity trading between utilities; without transmission

This chapter provides a brief look at the subject of utility facilities, electricity could not be moved from power

and nonutility organizational entities and their roles and plants to the thousands of distribution systems serving

relationships. It is intended to provide an essential basic millions of consumers of electric power.

understanding of the generation component terms used

throughout this report.

Utilities 

Electric utilities in general are defined as privately owned

companies and public agencies engaged in the generation,

transmission, and/or distribution of electric power for

public use. Electric utilities can be divided into the fol- 15

lowing four ownership categories, each with its own set of

distinct characteristics: investor-owned, Federally owned,

other publicly owned (i.e., owned by State, municipal, or

other governmental entities), and cooperatively owned

(see inset on page 10).

There are currently 3,199 utilities throughout the United

States (Table 1 and Figure 1), but only approximately 700

of them operate facilities that generate electric power.

Many electric utilities are exclusively distribution

utilities—that is, they purchase wholesale power from

others to distribute it, over their own distribution lines, to

the ultimate consumer. Three of the four types of utilities

actually sell more power at retail than they generate

(Figure 2).

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 have more than 10 electric

utilities operating in a county. In order to move electricity

among utilities, an extensive system of high-voltage

transmission lines is owned and operated by the Nation's

Investor-Owned Utilities

There are two basic organizational forms among investorowned companies. 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 investor-owned

utilities sell power at retail rates to several different

classes of consumers and at wholesale rates to other

utilities, including investor-owned, Federal, State, and

local government utilities, public utility districts, and rural

electric cooperatives. In 1995, only 244 of the 3,199 U.S.

utilities were investor owned, but they accounted for more

than 75 percent of both utility sales to ultimate consumers

and total utility generation.

Federal Utilities

According to Energy Information Administration (EIA)

classification, there are 10 Federal electric utilities in the

United States. They are:

 The Department of Energy's five power marketing

administrations (Alaska, Bonneville, Southeastern, 16

Southwestern, and Western Area Power Administrations)

 The Department of Defense's U.S. Army Corps of

Engineers 

 The Department of the Interior's U.S. Bureau of

Indian Affairs
10 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Major Characteristics of U.S. Electric Utilities by Type of Ownership

Ownership Major Characteristics

Investor-Owned Utilities (IOUs)

IOUs account for about three-quarters of

all utility generation and capacity. There

are 244 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 certain geographic areas

 Have obligation to serve and to provide reliable electric power

 Are regulated by State and sometimes 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 10 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

 The electricity generated by these agencies is marketed by Federal power

marketing administrations in DOE (Bonneville Power Administration,

Southeastern Power Administration, Southwestern Power Administration, and

Western Area Power Administration)

 The Alaska Power Administration is in the process of being privatized per

Public Law 104-58 enacted on November 28, 1995

 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 2,014 in the United States.

 Are non-profit State and local government agencies

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

contributions, economic and efficient facilities, and reduced rates

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

transmit; 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 land holdings)

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

Carolina Public Service Authority, are agencies of their respective State

governments

Cooperatively Owned Utilities

There are 931 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 (small rural farms and communities)

 Provide service mostly to members only

 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 cooperatives

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

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

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

December 1996).
WA

OR

CA

NV

ID

MT

WY

UT

AZ NM

TX

OK

CO

ND

SD

NE

KS

LA

AR

MO

IA

MN

WI

IL

MI

ID OH

PA

KY

TN

MS

AL GA

FL

SC

NC

WV

MD

DE

NJ

NY

VT

NH

ME

MA

RI CT

MAPP

(U.S.)

(U.S.)

WSCC SPP

ERCOT

SERC

MAIN

ECAR

NPCC

(U.S.)

MAAC

AK

ASCC

VA

VA

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 11

Table 1. Number of Electric Utilities by Class of Ownership and NERC Region, 1995

NERC Regiona

InvestorOwned Federal

State,

Municipal,

and Other

Government Cooperative Total

ASCC . . . . . . . . . . . . . . . . . . . 23 1 38 21 83

ECAR . . . . . . . . . . . . . . . . . . . 43 0 226 109 378

ERCOT . . . . . . . . . . . . . . . . . 6 0 66 59 131

MAAC . . . . . . . . . . . . . . . . . . . 19 0 50 19 88

MAIN . . . . . . . . . . . . . . . . . . . 18 1 148 45 212

MAPP . . . . . . . . . . . . . . . . . . . 14 0 489 183 686

NPCC . . . . . . . . . . . . . . . . . . . 55 0 126 10 191

SERC . . . . . . . . . . . . . . . . . . . 19 2 321 189 531

SPP . . . . . . . . . . . . . . . . . . . . 16 1 299 158 474

WSCC . . . . . . . . . . . . . . . . . . 28 5 251 138 422

Hawaii .................. 3 0 0 0 3

 U.S. Total .............. 244 10 2,014 931 3,199

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

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

 Note: See Figure 1 for a map of the regions. 

 Source: Energy Information Administration, Form EIA-861, “Annual Electric Utility Report” (1995).

Figure 1. North American Electric Reliability Council Regions for the Contiguous United States

and Alaska

 Regional Electric Area Council Areas: ECAR-East Central Area Reliability Coordination Agreement, SERC-Southeastern Electric Reliability

Council, MAIN-Mid-American Interpool Network, SPP-Southwest Power Pool, ERCOT-Electric Reliability Council of Texas, MAAC-Mid-Atlantic

Area Council, MAPP (U.S.)-Mid-Continent Area Power Pool, WSCC (U.S.)-Western Systems Coordinating Council, NPCC (U.S.)-Northeast

Power Coordinating Council, ASCC-Alaska Systems Coordinating Council.

 Source: North American Electric Reliability Council.
12 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 Source: Energy Information Administration, Form EIA861, “Annual Electric Utility Report” (1995).

Figure 2. Electric Utility Generation and Retail

Sales by Ownership Category, 1995

 The Department of the Interior's U.S. Bureau of

Reclamation

 The Department of State's International Water and

Boundary Commission

 The Tennessee Valley Authority. 

Of these, there are three major producers of electricity: the

Tennessee Valley Authority (TVA); the U.S. Army Corps

of Engineers (USCE); and the U.S. Bureau of Reclamation

(USBR). The TVA is the largest Federal power producer,

marketing its own power in both the wholesale and retail

markets. Generation by the USCE, except for the North

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

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

Federal power marketing administrations (PMAs)—

Bonneville, Southeastern, Southwestern, and Western

Area. These four PMAs also purchase energy for resale

from other electric utilities in the United States and

Canada. Alaska, the fifth PMA, operates its own power

plants and distributes power to ultimate consumers.

Federal power plants generated approximately 9 percent

of total utility electricity in the United States in 1995,

primarily from hydroelectric facilities. The Tennessee

Valley Authority generates electricity from coal and

nuclear power as well as hydropower. In 1995, only less

than 2 percent of the utility generation was sold by

Federal utilities to retail consumers. Consumers of

Federal power are usually large industrial consumers or

Federal installations. Most of the remaining energy

generated by Federal utilities is sold in the wholesale

market to publicly owned utilities and rural cooperatives

for resale. 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 divided into

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.

In 1995, publicly owned utilities accounted for almost 63

percent of the number of electric utilities in the United

States. They produced approximately 11 percent of total

utility generation and accounted for 14 percent of utility

sales to ultimate consumers. 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 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. The publicly owned power

districts are concentrated in Nebraska, Washington,

Oregon, Arizona, and California. In general, publicly

owned utilities tend to have lower costs than investor-owned utilities because they often have access to taxfree financing and do not pay certain taxes or dividends.

They also 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. 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)
Chemical 33%

Paper 25%

Petroleum 

 Refining 14%

Other

 Manufacturing 29%

Manufacturing 68%

Mining 5%

Other 6%

Electric,

Gas, and

Sanitary 

Services 21%

Total Nonutility Capacity in 

Manufacturing

47.6 Gigawatts

Total Nonutility Capacity

70.3 Gigawatts

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 13

FERC designations are not mutually exclusive categories among themselves, but, as a group, they and the two nonqualifying categories are mutually 17

exclusive.

See Chapter 4 for a discussion of qualifying facilities under PURPA. 18

This concept is discussed further in Chapter 4. 19

See Chapter 4 for a discussion of cogenerators. 20

Capacity is the amount of electric power delivered or required for which a generator, turbine, transformer, transmission circuit, station, or system is 21

rated by the manufacturer.

Figure 3. Shares of Nonutility Nameplate

Capacity by Major Industry Group, 1995

Note: Totals may not equal the sum of components due

to independent rounding.

Source: Energy Information Administration, Form EIA867, “Annual Nonutility Power Producer Report” (1995). 

are usually referred to as “power supply cooperatives.” make up this sector are usually engaged primarily in

These cooperatives are usually owned by the distribution producing, transporting, and/or distributing electricity,

cooperatives to whom they supply wholesale power. although they may be engaged primarily in steam, gas,

Distribution cooperatives resemble Federal utilities, water, and/or waste disposal services as a primary

supplying electricity to other utility consumers from their business. Unlike nonutilities in other sectors, these nongenerating capability. Cooperatives accounted for ap- utilities are engaged primarily in activities similar to the

proximately 6 percent of total utility generation and 8 generation activities carried out by electric utilities. The

percent of utility sales to ultimate consumers in 1995. remaining nonutility capacity is found either in the

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 forth by

PURPA; (3) exempt wholesale generators, which are

designated by FERC; (4) cogenerators not qualified under

PURPA; and (5) noncogenerators not qualified under

PURPA. QFs receive certain benefits under PURPA. In 17 18

particular, they are guaranteed that electric utilities will

purchase their output at a price based on the utility's

“avoided cost.” The characteristics of and major 19

differences among these categories of nonutilities are

shown in the inset on page 14.

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 1995, most nonutility

generating capacity (68 percent) was in the manufacturing

sector of the economy (Figure 3). Within the manufacturing sector, the chemical industry, with 33 percent of

the manufacturing total, the paper industry, with 25

percent, and petroleum refining, with 14 percent, generate

more electricity in their plants than all other manufacturing sectors combined. The manufacturing processes

conducted at many of these plants can utilize the thermal

energy produced when cogenerating electricity. After 20

manufacturing, the largest portion of nonutility electricity

generating capacity (21 percent) can be found in the

electric, gas, and sanitary services sector. The entities that

mining industry (5 percent) or in various other industries,

including agriculture, transportation, and other services (6

percent).

Recent Expansion of Utilities

and Nonutilities

There is a striking contrast between utilities and nonutilities, which can be seen by comparing their shares of

total electricity generating capacity and net additions to 21

capacity. Utilities have continued to dominate total

generating capacity (Figure 4). Even by 1995, their share

had only fallen to 91 percent. Utilities also continued to

dominate additions to capacity through 1989 (Figure 5).

However, in 1990, nonutilities added more capacity than

utilities did. This situation continued through 1994,
14 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Major Characteristics of U.S. Nonutilities by Type

Type Major Characteristics

Cogenerators (QF)  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).

Electric Power versus Electric Energy

Electric power is the rate at which electricity does work. It is measured at a point in time and has no time dimension. 

The maximum amount of electric power that a piece of electrical equipment can accommodate is its capacity or

capability. Its basic unit of measure is a watt.

Electric energy is the amount of work that can be done by electricity, i.e., it is the amount of electric power produced or

used over a specific time period. It is measured over a period of time and has a time dimension as well as an energy

dimension. The amount of electric energy produced or used during a specified period of time by a piece of electrical

equipment is its generation or consumption. Its basic unit of measure is a watthour.
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

2

4

6

8

10

12

Gigawatts

Utility Nonutility 

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 15

Two caveats regarding planned capacity additions should be kept in mind. Utilities must plan to build to meet expected demand; nonutilities have 22

no such requirement. Planned additions are not net of planned retirements, so they give an incomplete picture of changes in total capacity.

For example, see Energy Information Administration, Annual Energy Outlook 1996, DOE/EIA-0383(96) (Washington, DC, January 1996), p. 29. 23

Figure 4. Utility and Nonutility Nameplate

Capacity, 1985-1995

Figure 5. Utility and Nonutility Net Additions to

Nameplate Capacity, 1986-1995

 Source: Utility data: Energy Information Administration

(EIA), Inventory of Power Plants in the United States 1995,

DOE/EIA-0095(95) (Washington, DC, December 1996),

Table 1 (and previous issues); Nonutility data 1985-1988:

Edison Electric Institute, Statistical Yearbook of the Electric

Utility Industry 1991 (Washington, DC, October 1992), pp. 7

and 15; Nonutility data 1989-1995: EIA, Electric Power

Annual 1995, Volume II, DOE/EIA-0348(95)/2 (Washington,

DC, December 1996), Table 52 (and previous issues).

 Sources: Utility data: Energy Information Administration

(EIA), Inventory of Power Plants in the United States 1995,

DOE/EIA-0095(95) (Washington, DC, December 1996), Table

1 (and previous issues); Nonutility data 1986-1989: Edison

Electric Institute, Statistical Yearbook of the Electric Utility

Industry 1991 (Washington, DC, October 1992), pp. 7 and 15;

Nonutility data 1990-1995: EIA, Electric Power Annual 1995,

Volume II, DOE/EIA-0348(95)/2 (Washington, DC, December

1996), Table 52 (and previous issues).

but in 1995, utilities again added more capacity than shares of generation gives those not familiar with the

nonutilities. Another perspective for comparing utilities supply side of the industry a better perspective on the

and nonutilities is provided by looking at planned relative position each component holds in the electricity

additions to capacity. Utilities plan to add more capacity supply arena. This figure is also an excellent indicator of

than nonutilities in each of the next 3 years (Figure 6), the significant amount of change that has occurred in the 22

but the restructuring of the industry that is now going on nonutility segment of the industry.

tends to engender uncertainty about those plans.

The electric power industry has been dominated by

utilities—most importantly, regulated investor-owned

utilities. But nonutilities have been increasing their role in

the industry. This began with PURPA, when nonutilities

were seen as an energy-efficient, environment-friendly

source of electricity. Their role has continued to grow as

nonutilities have come to be seen as an economically

efficient, possibly competitive alternative to monopoly

utilities. Many industry observers expect the role of nonutilities to continue to grow.23

The amounts of energy generated by each component of

utilities and nonutilities in 1995 are compared with the

amounts generated in 1985 in Figure 7. Juxtaposing

The Interconnected Networks

The U.S. bulk power system has 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 (1) the Eastern Interconnected

System, consisting of the eastern two-thirds of the United
1996 1997 1998

0

1

2

3

4

5

6

Gigawatts

Utility Nonutility

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

For an in-depth study on the issue of U.S. electric power system reliability, refer to Energy Information Administration, Performance Issues for a 24

Changing Electric Power Industry, DOE/EIA-0586 (Washington, DC, January 1995).

Energy Information Administration, Electric Power Annual 1995, Volume II, DOE/EIA-0348(95)/2 (Washington, DC, December 1996), Table 36 25

(and previous issues).

As measured by wheeling delivered. 26

Figure 6. Utility and Nonutility Planned Additions

to Nameplate Capacity, 1996-1998

 Note: Indefinitely postponed and canceled units are not

included.

 Source: Utility data: Energy Information Administration,

Inventory of Power Plants in the United States 1995, DOE/EIA0095(95) (Washington, DC, December 1996). Nonutility data:

Energy Information Administration, Form EIA-867, “Annual

Nonutility Power Producer Report” (1995).

States; (2) the Western Interconnected System, consisting

primarily of the Southwest and areas west of the Rocky Even more dramatic is the growth in wholesale trade

Mountains; and (3) the Texas Interconnected System betweenregions of the National Electric Reliability Council

(Figure 8). The latter is not interconnected with the other (NERC). Historically, almost all wholesale trade was

two networks (except by certain direct current lines). The within NERC regions, but utilities are expanding

other two networks have limited interconnections to each wholesale trade beyond its traditional boundaries.

other. Both the Western and the Texas Interconnect are Between 1988 and 1994, one part of interregional

linked with different parts of Mexico. The Eastern and wholesale trade, purchases of electricity by investorWestern Interconnects are completely integrated with owned utilities, doubled its share of total wholesale

most of Canada or have links to the Quebec Province purchases from 5.0 to 10.1 percent.

power grid. Virtually all U.S. utilities are interconnected

with at least one other utility by these three major grids.

The exceptions are in Alaska and Hawaii. The

interconnected utilities within each power grid coordinate

operations and buy and sell power among themselves.

The bulk power system makes it possible for utilities to and the remainder is from Mexico. Imported power is

engage in wholesale (for resale) electric power trade. particularly important to the NPCC and MAPP regions of

Wholesale trade has historically played an important role, NERC, where gross imports were 9.8 and 7.7 percent, reallowing utilities to reduce power costs, increase power spectively, of retail sales by utilities in 1995. In contrast,

supply options, and improve reliability. In quantity, it gross imports for the Nation as a whole that year were 1.6 24

accounts for more than one-half of electricity sales to percent of retail sales by utilities.

ultimate consumers. Since 1986, the total amount of

wholesale power trade (as measured by purchased power Overall reliability planning and coordination of the

plus exchange received) among utilities and nonutilities interconnected power systems are the responsibility of

has grown at an average annual rate of 2.7 percent, NERC, which was voluntarily formed in 1968 by the 25

which is the same as the rate of growth for retail sales by

utilities. In the past, wholesale trade has been dominated

by utility purchases from other utilities. In 1995, utilities

purchased a total of 1,283 billion kilowatthours of

wholesale electricity from other utilities and a smaller but

increasing amount (222 billion kilowatthours) from

nonutility producers (Figure 9).

Wholesale power sales by nonutilities to utilities and

wheeling (the transmission of power from one point to

another) by utilities have both grown vigorously. Wholesale sales by nonutilities grew from 40 to 222 billion

kilowatthours between 1986 and 1995, which yields an

average annual growth rate over the period of 21.0 percent. Wheeling, while not increasing as spectacularly, 26

grew at an annual average rate of 6.9 percent over the

same period, a rate that is 2.5 times the growth rate for

sales to ultimate consumers. Whether these rates will be

sustained is uncertain, and more recent evidence is not

encouraging. Utility sales to ultimate consumers, wholesale sales by nonutilities, and wheeling by utilities all

grew more slowly between 1990 and 1995, with annual

growth rates of 2.1, 13.9, and 2.0 percent, respectively.

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

returned to the levels of the mid-1980s (Figure 10). U.S.

trade is mostly imports, which were more than five times

greater than exports in 1995. Normally, most imports are

from Canada (95 percent of total gross imports in 1995)
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 17

The Alaska System Coordinating Council was an associate member of NERC in 1988 and now they are a member. 27

Figure 7. Utility and Nonutility Generation and Shares by Class, 1985 and 1995

Includes facilities classified in more than one of the following FERC designated categories: cogenerator QF, small power a

producer QF, or exempt wholesale generator.

Cogen = Cogenerator.

EWG = Exempt wholesale generator.

 Other Non-QF = Noncogenerator Non-QF.

QF = Qualifying facility.

SPP = Small power producer.

 Note: •Sum of components may not equal total due to independent rounding. •Classes for nonutility generation are determined

by the class of each generating unit.

Source: Utility data: Energy Information Administration (EIA), Form EIA-861, “Annual Electric Utility Report” (1995), and EIA,

Electric Power Annual 1995, Volume I, DOE/EIA-0348(95)/1 (Washington, DC, July 1996), Table 8 (and previous issues);1985

nonutility data: Shares of generation estimated by EIA; total generation from Edison Electric Institute, Statistical Yearbook of the

Electric Utility Industry 1991 (Washington, DC, November 1992); 1995 nonutility data: EIA, Form EIA-867, “Annual Nonutility

Power Producer Report” (1995).

electric utility industry as a result of the 1965 power At present, the industry is in transition. Steady progress

failure in the Northeast. NERC's 10 regional councils toward competitive wholesale markets for electric power

cover the 48 contiguous States, part of Alaska, and recently has been accelerated by FERC Order 888, which 27

portions of Canada and Mexico (Figure 8). The councils opens access to transmission lines and encourages greater

are responsible for overall coordination of bulk power wholesale trade. In addition, the States are considering

policies that affect the reliability and adequacy of service opening retail markets to competition, and many are in

in their areas. They also regularly exchange operating and different stages of experimenting with this concept (see

planning information among their member utilities. The Part II of this report). The following chapter summarizes

boundaries of the NERC regions follow the service areas the legislative history that has paved the way for the

of the electric utilities in the region, many of which do not issuance of Order 888 and the industry’s pending move to

follow State boundaries. a competitive market environment.
18 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Regional Electric Reliability Council Areas:

ECAR — East Central Area Reliability SERC — Southeastern Electric Reliability

Coordination Agreement Council

MAIN — Mid-American Interpool Network SPP — Southwest Power Pool

MAAC — Mid-Atlantic Area Council ERCOT — Electric Reliability Council of 

MAPP (U.S.) — Mid-Continent Area Power Pool Texas

NPCC (U.S.) — Northeast Power Coordinating Council WSCC (U.S.) — Western Systems Coordinating

 Council

 Note: The Florida Reliability Coordinating Council (FRCC) was informally organized in October 1996 and, effective January 1,

1997, officially became a NERC region.

 Source: North American Electric Reliability Council.

Figure 8. Regions and Interconnections of the North American Electric Reliability Council in the

Contiguous United States, 1995
Utility 

Purchasers

InvestorOwned

Utilities

Federal

Other

Publicly Owned

Cooperatives

From 

Nonutilities

(222 billion

kilowatthours)

From Utilities

(1,283 billion

kilowatthours)

546

11

218.9

0.2

2.3

0.8

358

367

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

10

20

30

40

50

60

Gross Imports

Net Imports

Gross Exports

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 19

Figure 9. Electric Utility Wholesale Power Purchases by Ownership Type, 1995

(Billion Kilowatthours)

 Source: 1985-1994: Energy Information Administration,

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

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

Information Administration, Electric Power Annual 1995,

Volume II, DOE/EIA-0348(95)/2 (Washington, DC,

December 1996), Tables 40-42.

Figure 10. U.S. International Electricity Trade,

1985-1995

Note: Totals may not equal sum of components due to independent rounding.

Source: Energy Information Administration, Form EIA-861, “Annual Nonutility Power Producer Report” (1995).
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 21

4. Federal Legislative Impacts

This chapter describes Federal legislation that has had Policies Act of 1978 (PURPA), and the Energy Policy Act

major impacts on the electric power industry. The inset of 1992 (EPACT). The features of EPACT that led to FERC

below lists and summarizes the laws that have shaped the Orders 888 and 889 are discussed. (PUHCA and PURPA

industry since the 1930s. The remainder of the chapter have recently been targeted for repeal. Chapter 6 will

will focus on three Acts that have had profound effects on address the issues and arguments associated with the call

the industry's structure—the Public Utility Holding Com- for repeal, as well as current proposals for restructuring

pany Act of 1935 (PUHCA), the Public Utility Regulatory legislation that are before Congress.)

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 responsibility to adopt 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 break up the large and powerful trusts that controlled the Nation's electric and gas distribution

networks. PUHCA gave the Securities and Exchange Commission the authority to break up the trusts and to regulate the

reorganized industry in order to prevent their return.

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, as required by the Commerce Clause of the Constitution, 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.
Major Federal Legislation Affecting the Electric Power Industry (Continued)

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

Reclamation Project Act of 1939

(Aug. 4, 1939, ch. 418, 53 Stat. 1187)

This Act requires that rates for electric power generated at Federal hydroelectric projects be adequate to recover the powerrelated share of construction costs, to include interest charged at a rate of not less than 3 percent.

Flood Control Act of 1944

(Dec. 22, 1944, ch. 665, 58 Stat. 887)

This Act formed the basis for the later creation of the Southeastern Power Administration (SEPA) in 1950 to sell power a

produced by the U.S. Army Corps of Engineers in the Southeast; and the Alaska Power Administration (APA) in 1967 to both b

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

the Southwestern Power Administration’s (SWPA) authority after World War II came from the Flood Control Act of 1944, it was c

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

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, this Act provided authority for the establishment of the Western Area Power

Administration (WAPA) and transferred power marketing responsibilities and transmission assets previously managed by the e

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 (PMA)--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 as a

result of the Arab oil-producing nations’ ban on oil exports to the United States, 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.
Major Federal Legislation Affecting the Electric Power Industry (Continued)

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 23

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 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 provide residential consumers free conservation services 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

powers.

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 operations of the Bonneville

Power Administration (BPA). FERC approval is required for rates established under this Act. 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 plant of regulated electric utilities was 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, the FERC’s enforcement

powers have been increased substantially.”f

Tax Reform Act of 1986

(Public Law 99-509)

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

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

L. S. Hyman, America's Electric Utilities: Past, Present and Future, Fifth Edition (Arlington, VA: Public Utilities Reports, Inc., 1994), p. 111. 28

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 mandated that FERC open up the national electricity

transmission system to wholesale suppliers on a case-by-case basis.

 SEPA markets power in West Virginia, Virginia, North Carolina, South Carolina, Georgia, Florida, Alabama, Mississippi, a

Tennessee, and Kentucky. SEPA is unique from the other marketing authorities because it does not own any transmission

lines.

 The APA and the TVA are the only two Federal marketing organizations that operate their own plants. b

 SWPA markets power in Arkansas, Kansas, Louisiana, Missouri, Oklahoma, and Texas. c

 Energy Information Administration, Financial Statistics of Major U.S. Publicly Owned Electric Utilities 1994, DOE/EIA- d

0437(94)/2 (Washington, DC, December 1995), p. 458.

 The territory served by WAPA includes 15 Central and Western States of Arizona, California, Colorado, Iowa, Kansas, e

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.

 D. J. Muchow and W. A. Mogel, Energy Law and Transactions (Matthew Bender, April 1996), p. 53-20. f

 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).

The Public Utility Holding 

Company Act of 1935

The Public Utility Holding Company Act (PUHCA),

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.” The Act was passed at a time 28

when financial pyramid schemes were extensive. These

schemes allowed operating utilities in many areas of the

country to come under the control of a small number of

holding companies, which were in turn owned by other

holding companies. These pyramids were sometimes ten

layers thick. The following excerpt from America's Electric

Utilities: Past, Present and Future demonstrates the complexities that resulted from the leveraging that took place

within the holding company systems.
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 25

Samuel Insull worked for Thomas Edison and later became the vice-president of Edison General Electric Company. In 1887, Insull established the 29

Chicago Edison Co., and in 1897 Commonwealth Electric was formed. In 1907, Insull consolidated Chicago Edison and Commonwealth Electric to form

Commonwealth Edison Company.

L. S. Hyman, American’s Electric Utilities: Past, Present and Future, Fifth Edition (Arlington, VA: Public Utilities Reports, Inc., 1994), p. 102. 30

Ibid., p. 101. 31

The Securities and Exchange Commission actually noted 142 registered holding companies in 1939. Securities and Exchange Commission, Fifth 32

Annual Report of the Securities and Exchange Commission, Fiscal Year Ended June 30, 1939 (Washington, DC, 1940), pp. 1 and 43.

T. J. Brennan et al., A Shock to the System: Restructuring America’s Electricity Industry (Resources for the Future: Washington, DC, July 1996), 33

p. 160.

For a more extensive discussion of PUHCA, see Energy Information Administration, The Public Utility Holding Company Act of 1935: 1935-1992, 34

DOE/EIA-0563 (Washington, DC, January 1993), pp. 39-53.

The Insull interests [which operated in 32 states and thereby remaining in control without having paid a cent 29

owned electric companies, textile mills, ice houses, a

paper mill, and a hotel] controlled 69 percent of the stock

of Corporation Securities and 64 percent of the stock of

Insull Utility Investments. Those two companies

together owned 28 percent of the voting stock of Middle

West Utilities. Middle West Utilities owned eight

holding companies, five investment companies, two

service companies, two securities companies, and 14

operating companies. It also owned 99 percent of the

voting stock of National Electric Power. National, in

turn, owned one holding company, one service

company, one paper mill, and two operating companies.

It also owned 93 percent of the voting stock of National

Public Service. National Public Service owned three

building companies, three miscellaneous firms, and four

operating utilities. It also owned 100 percent of the

voting stock of Seaboard Public Service. Seaboard

Public Service owned the voting stock of five utility

operating companies and one ice company. The utilities,

in turn, owned eighteen subsidiaries.30

“Some holding companies were solid operations run for

no other purpose than to coordinate and make efficient

the operation of the subsidiary companies. But the

holding company movement became a craze because of

the promotional profits to be made. The holding companies were condemned and fell because of the excesses

committed. The present structure of the electric utility

industry is the direct result of legislation designed to

destroy the holding company that did not have an

operating rationale for its existence. As promoters saw the

huge profits to be gained from the holding company

business, they began to bid against each other to buy

operating properties to put into the holding companies.

Sometimes the promoters had to resort to odd measures to

make things look good. One could, for instance, combine

electric and ice properties, hiding the fact that most of the

earnings were coming from the competitive, unsafe, and

dwindling ice business. A good promoter could put

together a combination of companies, sell preferred stock

and bonds to the public to pay for the properties, take 10

percent or more as a commission, and keep the bulk (or

all) of the voting common stock of the holding company,

into the business.”31

Before PUHCA, almost half of all electricity generated in

the United States was controlled by three huge holding

companies, and more than 100 other holding companies

existed. The size and complexity of these huge trusts 32

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.’ ”33

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 requirements 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.34
26 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

J. Seligman, The Transformation of Wall Street and The History of the Securities and Exchange Commission in Modern Corporate Finance, 35

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

Public Utility Holding Company Act of 1935 (Public Law 74-333), Section 3. 36

The holding companies at first resisted compliance, and (1) such holding company, and every subsidiary comsome 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. As of January 35

1, 1995, there were only 15 registered holding companies

in the Unites States (Table 2). 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 . . . several times over the past 20 years. In the 1970s, utilities

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

detrimental to the public interest or the interest of

investors or consumers if—

pany 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;

(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.36

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

sought relief from PUHCA constraints in order to

diversify into nonutility lines of business as a means to

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

Table 2. Relative Size of Registered Holding Companies as of January 1, 1995

Holding Company System

Consolidated Consolidated Operating

Assets Revenues Retained Earnings

Twelve Months

a

Thousand Dollars

Allegheny Power System, Inc. (E) ........ 6,362,225 2,451,684 946,919

American Electric Power Company (E) .... 15,712,699 5,504,670 1,325,581

Central and South West Corp. (E) ........ 10,909,000 3,623,000 1,824,000

CINergy Corp. (E) ..................... 8,149,842 2,924,177 877,061

Columbia Gas System, Inc. (G) .......... 7,164,880 2,833,418 430,500

Consolidated Natural Gas Company (G) . . . 5,518,673 3,329,853 1,469,879

Eastern Utilities Associates (E) ........... 1,234,049 564,278 56,617

Entergy Corp. (E) ...................... 22,613,491 5,963,290 2,223,739

General Public Utilities Corp. (E) ......... 9,209,777 3,649,516 1,775,759

National Fuel Gas Company (G) ......... 2,041,618 1,102,746 375,013

New England Electric System (E) ......... 5,084,841 2,243,029 779,045

Northeast Utilities (E) ................... 10,584,880 3,642,742 946,988

PECO Energy Power Company (E) ....... 102,585 15,714 7,471

Southern Company (E) ................. 27,042,887 8,297,387 3,191,000

Unitil Corp. (E) ........................ 204,521 153,416 27,183

 Total ............................... 131,935,968 46,298,920 16,256,755

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

in the business.

E = Electric.

G = Gas.

Source: Securities and Exchange Commission, Financial and Corporate Report (Washington, DC) (not dated).
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 27

J. H. Minan and W. H. Lawrence, “Federal Tax Incentives and Solar Energy Development,” Energy Law Service, Monograph 7F (Wilmette, IL, 37

September 1981), p. 5.

Public Utility Regulatory Policies Act of 1978 (Public Law 95-617), Section 2. 38

The law required electric utilities to purchase electricity from qualified facilities at “a rate which [does not] exceed the incremental cost to the electric 39

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).

Energy Information Administration, Renewable Energy Annual 1995, DOE/EIA-0603(95) (Washington, DC, December 1995), p. xxvi. 40

to diversify in order to exploit the positive experience of (1) a program providing for increased

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, the Arab oil-producing nations 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: the

Public Utility Regulatory Policies Act (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.37

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

congressional authority under the Constitution to

regulate interstate commerce require—

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 . . .38

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. This 39

provision created, by fiat, 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 problems that had

made entry into the electricity market prohibitive for most

of the smaller energy producers.40

In passing 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

electricity. Instead, the prices they are paid reflect the

avoided cost of the purchasing utility, that is, the cost the
28 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

W. H. Wellford and H. E. Robertson, “Bidding for Power: The Emergence of Competitive Bidding in Electric Generation,” Working Paper No. 2, 41

National Independent Energy Producers (March 1990), p. 3.

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. 42

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. Because of amendments to PURPA in 1990, the term “small power

producer” is now a misnomer. The amendments eliminated the original size criterion for all energy sources except hydroelectric,

while maintaining the criterion for the type of energy used. (Under PURPA provisions, both cogenerators and small power

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

Cogenerators Renewables

Cogenerators are generators that sequentially or simultaneously A renewable resource is an energy source that is regenerative

produce electric energy and another form of energy (such as or virtually inexhaustible. Renewable energy includes solar,

heat or steam) using the same fuel source. Cogeneration wind, biomass, waste, geothermal, and water (hydroelectric).

technologies are classified as “topping-cycle” and “bottoming- Solar thermal technology converts solar energy through high

cycle” systems. In a typical topping-cycle system, high- concentration and heat absorption into electricity or process

temperature, high-pressure steam from a boiler is used to drive energy. Wind generators produce mechanical energy directly

a turbine to generate electricity. The waste heat or steam through shaft power. Biomass energy is derived from hundreds

exhausted from the turbine is then used as a source of heat for of plant species, various agricultural and industrial residues, and

an industrial or commercial process. In a typical bottoming-cycle processing wastes. Industrial wood and wood waste are the

system, high-temperature thermal energy is produced first for most prevalent form of biomass energy used by nonutilities.

applications such as reheat furnaces, glass kilns, or aluminum Geothermal technologies convert heat naturally present in the

metal furnaces, and heat is then extracted from the hot exhaust earth into heat energy and electricity. Hydroelectric power is

stream of the primary application and used to drive a turbine. derived by converting the potential energy of water to electrical

Bottoming-cycle systems are generally used in industrial energy using a hydraulic turbine connected to a generator. 

processes that require very high-temperature heat.

For a nonutility to be classified as a cogenerator qualified under PURPA, it also must meet certain ownership and operating

PURPA, it must meet certain ownership, operating, and criteria established by FERC. In addition, renewable resources

efficiency criteria established by FERC. The operating must provide at least 75 percent of the total energy input.

requirements stipulate the proportion (applicable to oil-fired PURPA provisions enabled nonutility renewable electricity

facilities) of output energy that must be thermal energy, and the production to grow significantly, and the industry responded by

efficiency requirements stipulate the maximum ratio of input improving technologies, decreasing costs, and increasing

energy to output energy. efficiency and reliability.

For a nonutility to be classified as a small power producer under

utility avoided by not producing the electricity received had previously decided that avoided-cost rates for QFs

from the QF or purchasing it from another source. One were to be based on the cost of production of electricity by

initial interpretation of avoided cost under PURPA was nuclear facilities. These high rates spurred a larger

the cost of additional electricity produced by the utility volume of offers than CMP needed. The switch to marketitself. However, under PURPA's requirements, some based pricing provided a new avoided cost for purchased

utilities which already had sufficient supply available to power from QFs that was below the initial avoided cost

meet demand, either through their own generation or levels that would have prevailed in the absence of

through purchases from other sources, in addition had to bidding.

purchase QF generation. 

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

41

The Energy Policy Act of 1992

In 1992, President George Bush signed the Energy Policy

Act (EPACT), which 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 includes language that

created a new category of power producers, called exempt

wholesale generators (EWGs). By exempting them from 42
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 29

Southeastern Power Administration v. Kentucky Utilities Company, 25 FERC § 61,204 (1983). 43

Otter Tail Power Company v. Federal Power Commission, 410 U.S. 366 (1973). 44

Alabama Power Company v. Nuclear Regulatory Commission, 692 F.2d 1362 (11th Cir. 1982). 45

PUHCA regulation, the law eliminated a major barrier for and the creation of a category of entities exempt from SEC

utility-affiliated and nonaffiliated power producers who regulation. However, the most bitter dispute over

want to compete to build new non-rate-based power PUHCA reform was in the area of transmission access.

plants. EWGs differ from PURPA QFs in two ways. First, Some nonutility groups had argued that revising PUHCA

they are not required to meet PURPA's cogeneration or without revising transmission-access rules would reinrenewable fuels limitations. Second, utilities are not force the utility monopolistic structure. The main thrust

required to purchase power from EWGs. Marketing of of the argument against PUHCA reform with increased

EWG power will probably be facilitated by transmission transmission access authority was that the high level of

provisions that gave FERC the authority to order utilities reliability enjoyed by the Nation would be compromised.

to provide access to their transmission systems.

The law has been hailed as one of the most significant obligation to provide access to their transmission lines

pieces of legislation in the history of the industry. In before EPACT, there are several restricted exceptions to

addition to giving EWGs and QFs access to distant this generalization. One is the requirement, under

wholesale markets, the law provides transmission- PURPA, that utilities interconnect with and purchase

dependent utilities the ability to shop for wholesale power power from QFs. Another is that under the Federal Power

supplies and frees such utilities, mostly municipals and Act, as amended by PURPA, FERC had the authority to

rural cooperatives, from their dependency on surrounding require wheeling under limited circumstances. But, in its

investor-owned utilities for wholesale power require- first deliberation on this authority, FERC found that the

ments. The transmission provisions have led to a nation- authority was limited so that it did not allow FERC to

wide open-access electric power transmission grid for require a utility to wheel power to its wholesale customers

wholesale transactions. (The law specifically prohibits or to encourage competition in bulk power markets.

FERC from ordering retail wheeling--the transmission of This interpretation of PURPA circumscribed the conpower to a final customer.) Independent power ditions under which FERC could order wheeling. The

producers, publicly owned utilities, rural cooperatives, interpretation by FERC was later upheld by the courts.

and industrial producers (i.e., anyone selling power at However, the enactment of EPACT broadened FERC's

wholesale) gained the ability to win from FERC orders authority to order wheeling.

that require transmission-owning utilities to provide

transmission service at FERC-defined “just and The Federal courts can also require wheeling, but only

reasonable” rates. when the Sherman Antitrust Act has been violated.

The language of the law concerning pricing directs FERC, wheel power is determined to be anticompetitive or an atwhen it issues a transmission order, to approve rates tempt to monopolize a particular market. Also, under the

which permit the utility to recover “all legitimate, Atomic Energy Act, the Nuclear Regulatory Commission

verifiable economic costs incurred in connection with the and the U.S. Attorney General may require wheeling

transmission services.” Such costs include “an appro- access as a condition for issuing a construction permit for

priate share, if any, [of] necessary associated services, a nuclear plant. EPACT broadened available exceptions

including, but not limited to, an appropriate share of any substantially by giving FERC new authority to order

enlargement of transmission facilities.” The language also utilities to provide wheeling over their transmission syssays that FERC “shall ensure, to the extent practicable,” tems to utilities and nonutilities. FERC implementation of

that costs incurred by the wheeling utility are recovered this legislation is described in Chapter 7 of this report.

from the transmission customer rather than “from a transmitting utility's existing wholesale, retail, and trans- In addition to the preceding statutory background regarmission customers.” ding the electric power industry, the inset below provides

Probably the most salient characteristics of EPACT's and decisions that have had major impacts on the

reforms to PUHCA were the expansion of FERC authority industry.

Although regulated public utilities had no general

43

44

Violations include circumstances in which a refusal to

45

a synopsis of a related subject—U.S. Supreme Court cases
30 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Major U.S. Supreme Court Cases Affecting the Electric Power Industrya

Court Case Date Decision

Munn v. Illinois 1877 The Supreme Court establishes the rights of government to regulate

(94 U.S. 113) and set rates for companies that provide vital public services in a

monopolistic business environment.

Smith v. Ames 1898 The Supreme Court decrees just compensation on fair value. The

( 169 U.S. 466) 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 1927 The Supreme Court declares that selling electricity interstate cannot be

(273 U.S. 83) regulated by a State.

Ashwander v. TVA 1936 The Supreme Court upholds the constitutionality of the Tennessee

(297 U.S. 288) Valley Authority.

Electric Bond & Share v. SEC 1938 The Supreme Court upholds the Holding Company Act of 1935.

(303 U.S. 419)

Tennessee Electric Power Co. v. 1939 The Supreme Court rules in TVA’s favor, despite the claims that TVA

Tennessee Valley Authority threatened the large investments already made by privately owned

(306 U.S. 118) utilities. This ruling resulted in TVA becoming a major electricity

supplier in the region.

F.P.C. v. Hope Natural Gas 1944 The Supreme Court closes a longstanding dispute by allowing either

(320 U.S. 591) original or replacement cost accounting in utility rate making, so long

as just and reasonable rates result.

Otter Tail Power Co. v. United States 1973 The Supreme Court finds Otter Tail Power Co. in violation of Section 2

(410 U.S. 366) of the Sherman Act, for refusing to sell or wheel wholesale power to

proposed municipal systems.

FPC v. Conway Corp. 1976 The Supreme Court states that FERC, in setting wholesale rates, must

(426 U.S. 271) act consistently with the policies of the Federal antitrust laws.

Burke v. Narragansett Electric Co. 1978 The Supreme Court affirms primacy of FERC rate setting.

(435 U.S. 972)

FERC v. Mississippi 1982 The Supreme Court upholds the constitutionality of PURPA.

(456 U.S. 742)

American Paper Institute v. American 1983 The Supreme Court upholds the constitutionality of FERC’s

Electric Power Service Corp. cogeneration rules promoted pursuant to PURPA. 

(461 U.S. 402)

Nantahala Power & Light Co. v. Thornburg 1986 Among other outcomes, the Supreme Court confirms that FERC has

(476 U.S. 953) exclusive authority over wholesale electric rates.

Mississippi Power & Light Co. v. 1988 The Supreme Court determines that FERC authority is controlling and

Mississippi that a State commission is obligated to honor a FERC order. The b

(487 U.S. 354) 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
Major U.S. Supreme Court Cases Affecting the Electric Power Industry (Continued)

Court Case Date Decision

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 31

Duquesne Light Co. v. Barasch 1989 “U.S. Supreme Court held that absent any showing that a State’s rate d

(48 U.S. 299) making 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

 This inset highlights the major U.S. Supreme Court cases that affect the electric power industry, stating the final decision of a

the Court without discussing in detail the contents of the case.

 This case, Mississippi Power & Light Co. v. Mississippi, continues the holding found by the U.S. Supreme Court in the b

Nantahala Power & Light Co. v. Thornburg case.

 W. F. Fox, Jr., Regulatory Manual Series: Federal Regulation of Energy (Shepard’s/McGraw-Hill, Inc., 1993), p. 149. c

 This case is a final construction work in progress (CWIP) case. FERC issued a CWIP rule effective July 1, 1983 (see 48 d

Fed. Reg. 24323 (June 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.

 W. F. Fox, Jr., Regulatory Manual Series: Federal Regulation of Energy (Shepard’s/McGraw-Hill, Inc., 1993), p. 153. e

 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: 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: An Update 35

 H.R. Linden, “The Revolution Continues,” The Electricity Journal, Dec. 1995, pp. 55-56. 46

 EPACT has ameliorated these differentials at the wholesale level by allowing some wholesale customers access to lower cost power. 47

5. Factors Underlying the Restructuring

of the Electric Power Industry

In recent years, economists and other public policy competitors in other areas pay far less for a kilowatthour

analysts have stressed the advantages of competition over of electricity. These price differentials are another factor

regulated monopolies and have promoted the idea that underlying the restructuring of the industry.

free markets can drive down costs and prices by reducing

inefficiencies. Competitive industries also may 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 an existing regulated

monopoly. Originally, protecting consumers was a primary motivation for decisions to impose regulatory constraints on the industry. Today, legislators and regulators

are instituting laws and rules that promote competition

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.

Examples of this changed climate occur at the State and

Federal levels as well as in other countries of the world.

In the United States, the Energy Policy Act of 1992 was

enacted by the Federal Government to promote competition in electricity generation. Regulators in the State of

New Hampshire have required price roll-backs for electricity, and many other States are in the process of instituting retail competition in their respective jurisdictions.

Many individuals and groups in California have asked

regulators and legislators to allow new companies to

generate and sell electricity. This changed climate is one

of the factors underlying restructuring.

For most of the industry's history, consumers welcomed

the protection that regulation afforded them and felt that

this means of oversight assured them that the prices they

were paying were fair. Now, however, the consumers

themselves are pushing for competition 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

A third factor that has had a significant impact on

restructuring is technological advances in the production

of electricity. This factor has allowed nonutilities, using

recently advanced, aero-derivative gas turbine technologies, to generate electricity more cheaply than the

total (regulatory) costs of many utilities that now use

previously developed fossil-fueled or nuclear-fueled

steam-electric technologies. Also, the advanced gen- 46

erators are cleaner and use less fuel. Nonutilities are able

to put advanced generators into operation quickly, sometimes as an alternative to utility capacity that is already

built.

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

quantify these factors where they are relevant.

Price Differences

While restructuring originated in fact with PURPA, large

differences in the retail prices of electricity have continued

to motivate some to advocate expanded restructuring. 47

The current structure of the electric power industry does

not provide retail customers of utilities, in general, with

the opportunity to purchase electricity from sources that

may have lower prices than their current suppliers.

Restructuring the industry holds the possibility of

allowing more choice for consumers. Many industrial

customers of utilities, 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.
36 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 T. R. Kuhn, et al., “Electric Utility Deregulation Sparks Controversy,“ Harvard Business Review (May/June 1996), p. 150. 48

 Because industrial consumers usually consume larger amounts of electricity than other consumers, and because they usually take it at higher voltages, 49

the cost of providing each unit of electricity to them is lower.

 Source: Energy Information Administration, Form EIA-861, “Annual Electric Utility Report,” (1995).

Figure 11. Average Revenue from Electricity Sales to All Retail Consumers by State, 1995

(Cents per Kilowatthour)

They argue that price differentials among utilities provide included California, the Northeast (including all the New

an advantage to the competitor who is situated in an area England States), and States outside the contiguous United

with lower electricity prices, and that all consumers States. It is probably not coincidental that many of the

should have access to cheaper electricity. Some industrial States that are leaders in the restructuring of retail

consumers, who have threatened to purchase power from electricity markets are among the States with high average

lower-priced providers, move the location of their com- revenues. In contrast, States with average revenues below

panies, or generate their own electricity, often have 6 cents per kilowatthour were scattered throughout the

“succeeded in wringing lower prices from their traditional rest of the country. Most had average revenues from all

electric utilities.” consumers that were less than one-half those in States 48

In the United States, the average revenue received per pattern exists for average electricity revenues received

unit of electricity sold to all retail consumers varies sub- from industrial consumers, although industrial consumers

stantially by State (Figure 11). In 1995, the States with yield one-third lower average revenues than all retail

average revenues of 9 cents per kilowatthour and above customers (Figure 12). 

with the highest average revenue. A similar geographic

49
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 37

 Energy Information Administration, Electric Power Annual 1992, DOE/EIA-0348(92) (Washington, DC, January 1994), p. 104. 50

Figure 12. Average Revenue from Electricity Sales to Industrial Consumers by State, 1995

(Cents per Kilowatthour)

 Source: Energy Information Administration, Form EIA-861, “Annual Electric Utility Report,” (1995).

Large industrial consumers have played a substantial role price has been falling faster than the average price

in motivating the restructuring of the electric power in- charged to all consumers.

dustry. Their bargaining power as consumers is reflected

in the declining trend of industrial prices relative to those Over the years, utilities have developed programs to help

for all consumers. While industrial consumers have paid lower the price of electricity to the industrial sector. They

a lower average price for electricity than other consumers traditionally have relied on alternative rate design apfor many years, the ratio of industrial revenues relative to proaches, such as interruptible service and time-of-use

prices for all consumers has shown two opposing trends. rates, to reduce the time-variation of demand by the inThe price that industrial consumers paid for electricity dustrial sector. The programs also use technological aprelative to the price that all consumers paid rose from the proaches, such as thermal storage. A number of utilities

mid-1960s until 1983; since then, it has declined (Figure have developed flexible custom measure programs, which

13). Because real average revenues from both groups allow industrial energy users and utilities to work tohave been falling since 1983, the relatively lower revenues for industrial consumers indicate that their average

gether to identify cost-effective programs. 50
38 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 H.R. Linden, “The Revolution Continues,” The Electricity Journal (December 1995), p. 54. 51

 R.E. Balzhiser, “Technology—It’s Only Begun to Make a Difference,” The Electricity Journal (May 1996). 52

 Energy Information Administration, Annual Energy Outlook 1996, DOE/EIA-0383(96) (Washington, DC, January 1996), p. 32. 53

 Energy Information Administration, AEO97 National Energy Modeling System run AEO97B.D100296K. 54

 Energy Information Administration, Financial Statistics of Major U.S. Investor-Owned Electric Utilities 1994, DOE/EIA-0437(94)/1 (Washington, 55

DC, December 1995), Table 14.

Ibid., Tables 41 and 43. 56

 H.R. Linden, “The Revolution Continues,” The Electricity Journal (December 1995), p. 55. 57

 Source: Energy Information Administration, Annual Energy

Review 1995, DOE/EIA-0384(95) (Washington, DC, July

1996), Table 8.11.

Figure 13. Relative Average Revenue of

Electricity Sales: Ratio of Industrial

Consumers to All Consumers,

1960-1995

Table 3. Total Projected Additions of Electricity

Generating Capability for Electric

Generators by Technology Type, 

1995-2015

(Gigawatts)

Technology Capability Additions

Coal Steam ................ 35.5

Combined Cycle ............ 138.1

Combustion Turbine/Diesel . . . 114.5

Nuclear Power . . . . . . . . . . . . . . 1.2

Fuel Cells . . . . . . . . . . . . . . . . . . 2.1

Renewable Sources ......... 10.6

Total ...................... 302.0

 Source: Energy Information Administration, AEO97 National

Energy Modeling System run AEO97B.D100296K.

Technological Advances

The restructuring of the electric power industry has been

sustained 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].” These improve- 51

ments 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. 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.52

In its modeling of the electric power industry, EIA compares the estimates of the costs of different generating

technologies. In its forecasts, “[t]echnology types for new

electric generating capability are chosen on the basis of

cost while meeting local and Federal emissions constraints.” The reference case forecast recently released 53

by EIA projects that, of the 302 gigawatts of new

generating capability projected to be added by electric

generators between 1995 and 2015, more than 80 percent

will be either combined-cycle or combustion turbine technology (Table 3).54

The operating and maintenance costs for fossil-fueled

steam-electric and nuclear steam-electric generation at

major investor-owned electric utilities averaged about 2.2

cents per kilowatthour in 1994, but some of these utilities 55

reported operating and maintenance costs in excess of 3

cents per kilowatthour in 1994. Total costs, including 56

operating and maintenance plus capital costs, average 3

cents per kilowatthour for the new combined-cycle gas

turbine technologies. Based on these data, combined- 57

cycle gas turbines apparently can be built and operated

more cheaply than some existing utility steam-electric

generation. Therefore, in many cases, it is less expensive

for nonutilities (or utilities) to build new capacity than to

operate some of the more expensive capacity that is

already in existence.

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: An Update 39

The following discussion regarding the pros and cons of both PUHCA and PURPA repeal reflect the views of numerous groups associated with the 58

electric power industry. The discussion does not purport to represent the views of the Department of Energy or the Administration.

Each Congress lasts for 2 years, commencing in January of the year following the biennial election of Members, and is divided into two sessions. 59

If a bill is not enacted into law by the end of a certain Congress, it must be reintroduced into the next Congress for consideration.

For a discussion of these abuses, refer to Chapter 4. 60

For further discussion of these changes, see Energy Information Administration, The Public Utility Holding Company Act of 1935: 1935-1992, 61

DOE/EIA-0563 (Washington, DC, January 1993), p. 23.

6. Federal Legislative Initiatives for Change:

The Issues

Some groups contend that two particular statutes are that it has been rendered obsolete because of changes that

irrelevant in an era of competition, and that these statutes have occurred in the latter part of this century which

are actually hindering the industry's transition from a preclude the holding company abuses of yesterday.

regulated monopoly. They are the Public Utility Holding They are specifically:

Company Act of 1935 (PUHCA) and the Public Utility

Regulatory Policies Act of 1978 (PURPA). This chapter  The development of an extensive disclosure system

addresses the current debate over the repeal of these for all publicly held companies

laws and examines miscellaneous proposals that were 58

introduced during the 104th Congress to deal with  The increased competence and independence of 59

restructuring. The discussion focuses on several bills that accounting firms

were introduced for the purpose of providing a comprehensive and Federally guided national approach to com-  The development of accounting principles and

petition in the electric power industry. auditing standards and the means to enforce them

The Current Debate Over PUHCA

Although a vigorous debate is now taking place as to

whether PUHCA's provisions are relevant today, there

seems to be little question among the debaters that six

decades ago PUHCA was the right law at the right time.

PUHCA achieved what it was designed to do—it broke up

the large and 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

feel strongly that, until the industry completes the transition, PUHCA's regulations must stay in effect in order to

protect consumers. Arguments for and against the repeal

of PUHCA are summarized in the inset below.

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

60

 The increased sophistication and integrity of security

markets and security professionals

 The increased power and ability of State regulators.61

In the mid-1980s, the Securities and Exchange Commission (SEC) determined that PUHCA had achieved its

purpose and recommended repeal, but no action was

taken in Congress. In 1994, the SEC again initiated a

study in order to develop a staff recommendation to either

repeal or reform PUHCA or to leave the law intact. In

July 1994, the SEC conducted a round table discussion

concerning whether or not the fundamental premise of the

law and its provisions for addressing problems associated

with monopolies and anticompetitive behavior were still

relevant in the current increasingly competitive marketplace. In an attempt to obtain a broad cross-section of

views on the subject, Federal, State, and local regulators

and high-level representatives from utilities, consumer

groups, trade associations, investments banks, etc., were

invited to participate in the discussion. Later in the year,

the SEC published a notice in the Federal Register requesting comments on the subject.
40 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

S.1317, “Public Utility Holding Company Act of 1995,” 104th Congress, 1st Session (October 12, 1995), p. 2. 62

The Pros and Cons of PUHCA Repeal

Against Repeal For Repeal

  PUHCA regulations can protect consumers until

full retail competition is up and running.

  Ratepayers are still at the mercy of the regulated

monopolies.

  PUHCA guards against monopolies and

anticompetitive behavior.

  Utility monopolies are now taking actions (e.g.,

mergers) to increase market dominance, and

PUHCA can keep them in control.

  Immediate repeal is a piecemeal approach; repeal

should be contained in comprehensive industry

restructuring legislation.

  PUHCA guards against interaffiliate transaction

abuse.

 PUHCA’s provisions are antiquated.

 PUHCA is impeding the transition to competition.

 Utilities need to be able to diversify in order to

improve profits.

 PUHCA has already achieved its goal by making

holding companies manageable and regulated.

 The Securities and Exchange Commission itself

recommends a conditional repeal.

 PUHCA prevents all companies from playing on a

level field.

 Various other regulations have since been

instituted that prevent holding company abuse.

 Immediate repeal is necessary; it will take too long

if it is contained in comprehensive industry

restructuring legislation.

 Source: The pros and cons listed in this inset were compiled from articles published in various energy-related

journals.

Based on the comments received, the earlier round table Alphonse D'Amato (R-NY) “is intended to eliminate

discussion, and consultations with the National Asso- unnecessary regulation, yet still provide for consumer

ciation of Regulatory Utility Commissioners (NARUC), protection by providing for State commission access

the SEC's Division of Investment Management released a to books and records of all companies in a holding

report listing three legislative options to give utility company system, and for Federal audit authority and

holding companies more flexibility. The Division recom- oversight of affiliate transactions, to the extent that

mended an option that dealt with conditional PUHCA such activities affect rates, while, at the same time,

repeal in a minimum 1-year transition period. The con- affording companies the flexibility required to

ditions included access by State regulators to the books compete in today's energy markets.”

and records of companies within a holding company

system, FERC authority to exercise oversight of affiliate  H.R. 3601, Public Utility Holding Company Act of

transactions, and, generally, that energy consumers would 1996, introduced on June 6, 1996, by Congressman W.

not lose the protection of the Federal Government. J. Tauzin (R-LA) would repeal the 1935 Act and

Two bills (which are not considered comprehensive conflict of jurisdiction guidelines.

restructuring legislation) were introduced in the 104th

Congress that would repeal PUHCA: The bills' supporters believe that speedy passage is of

 S. 1317, Public Utility Holding Company Act of of the electric industry. They contend that the original

1995, introduced on October 12, 1995, by Senator PUHCA prevents all companies from competing on a

62

would amend the Federal Power Act to repeal its

utmost importance, given the rapidly changing makeup
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 41

J. Anderson, “Commentary: Pro & Con,” Public Utilities Fortnightly (July 15, 1995), p. 38. 63

For a discussion of the events that led to PURPA and how it affected the industry, refer to Chapter 4. 64

level playing field, which some believe is a necessity in a

competitive market. Under the current law, the SEC

imposes the business and financial restrictions which

companies feel are unfair in the current changing

environment. The major restrictions include: 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, but

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. 

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 who are at

present aggressively taking actions, such as merging and

diversifying, perhaps to increase their market dominance.

According to John Anderson, Executive Director of the

Electricity Consumers Resource Council (ELCON), “A

repeal of PUHCA while the retail franchises remain in

place would further expose hostage ratepayers to the risks

of interaffiliate abuse and ill-advised utility forays into

unrelated businesses.” 63

Most opponents of the legislative proposals to repeal

PUHCA stress that what they are against is immediate,

standalone action. Instead, they want to see well-thoughtout, comprehensive restructuring and deregulation

legislation that will deal with all industry issues,

including retail wheeling, stranded investment, PURPA,

and FERC jurisdiction, as well as with repeal of PUHCA.

Still other groups believe that even after a fully competitive market is established, PUHCA-type regulation

will continue to be necessary in order to ensure that the

market remains competitive. 

The Current Debate Over 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. It was 64

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.

Those arguments are summarized in the inset below.

Legislation (which is not considered comprehensive

restructuring legislation) was introduced into both Houses

during the 104th Congress to address Section 210 of

PURPA, which requires electric utilities to buy power

from qualifying cogeneration and small power production

facilities. They are specifically:

  S. 708, Electric Utility Rate Payer Act, introduced by

Senator Don Nickles (R-OK) on April 6, 1995, which

would repeal Section 210 while stipulating that

contracts in place before October 31, 1995, would still

be in effect, but that no electric utility would be

obliged to enter into any new contracts after that date.

  H.R. 2562, Ratepayer Protection Act, introduced by

Congressman Cliff Stearns (R-FL) on October 31,

1995, which would suspend Section 210 for any

utility meeting specific eligibility criteria for a “certification of competition” from its State public utility

commission.

Proponents of PURPA reform or repeal 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,
42 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Energy Information Administration, Renewable Energy Annual 1995, DOE/EIA-0603(95) (Washington, DC, December 1995), pp. xxvi-xxvii. 65

The Pros and Cons of PURPA Repeal

Against Repeal For Repeal

  There is no guarantee that a free market can sustain

the goals of PURPA, especially in the use of

cogeneration and renewables.

  PURPA is anticompetitive because utilities are required to

purchase from QFs.

  Our Nation must be able to handle another energy crisis

through fuel diversity.

  EPACT’s provisions for exempt wholesale generators

render PURPA obsolete.

  Incentives must remain in place to conserve energy and

to use more environmentally benign fuels.

 

  PURPA has resulted in high prices to consumers

because QF contract terms were lengthy and were based

on erroneous forecasts of high capital costs and

increases in demand and the price of natural gas.

  Qualifying facilities (QFs) bring increased reliability and

decrease the need for large costly plants.

  PURPA’s goals have already been achieved.

  At this point, utilities still have too much market power

and PURPA levels the playing field for nonutilities.

  If natural gas will be the fuel of choice as predicted, the

environment will not need PURPA’s strict protection since

natural gas is the least harmful fossil fuel.

  Immediate repeal is a piecemeal approach—repeal

should be included in comprehensive industry

restructuring legislation.

  Cogenerators and renewables have already gotten

a foothold and do not need further promotion.

  Immediate repeal is necessary; it will take too long

if it is contained in comprehensive industry restructuring

legislation.

 Source: The pros and cons listed in this inset were compiled from articles published in various energy-related journals.

although the Act introduced competition, it can hardly be electricity and construction of new generating capacity.

said that it did so in an atmosphere of free market From the perspective of the QFs, rates above current

participation, a basic tenet of economic theorists who avoided cost (6 cents per kilowatthour or higher) and

stress that the rules and prices must be established by the long-term commitments (often 10 years) were essential to

market—not by the Government. In addition they assert establish the QF power market. By the late 1980s and

that, because of EPACT’s creation of exempt wholesale early 1990s, however, oil prices had stabilized, natural

generators and its incorporation of competitive policies, gas prices had declined, and excess generating capacity

PURPA’s QF concept has been overtaken by events; i.e., in most regions of the country allowed utilities to buy

the industry now realizes that nonutilities can, on the capacity and energy at much lower prices than had been

whole, cleanly and efficiently provide additional forecast a decade earlier. The utilities' actual avoided

generating capacity. costs dropped lower than in the mid-1980s and were

 considerably lower than the levels required by the longThose who want PURPA eliminated now say that its term contracts imposed by some State commissions.

mandatory purchase clause is anticompetitive and Many utilities contend that PURPA has caused dramatic

therefore is impeding the transition to competition. hikes in retail electric rates, and many groups along with

Furthermore, QFs have been receiving long-run avoided- these utilities now believe that new regulatory action

cost rates that today substantially exceed current market must be taken to correct past misjudgments.

prices. These rates were based on erroneous forecasts of

sharply rising oil and natural gas prices as well as the Forecasters have predicted that future power generation

expectation of future increases in the demand for will be dominated by natural gas. Reformers argue that,

65
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 43

This is the concept of “sustainable development,” which refers to ways of social, economic, and political progress that meet the needs of the present 66

without compromising the ability of future generations to meet their needs. Sustainable development points to ways that the economy can continue to develop

without destroying the environment.

based on these forecasts, PURPA becomes irrelevant renewable technologies.) To some groups, just as

because natural gas is inexpensive and the most environ- there is no guarantee that competition can further the

mentally benign of all the fossil fuels used in electric goals of PURPA, there is also no question that incentives

power generation. As mentioned earlier, some groups must remain in place to do so. One incentive already in

contend that PURPA is no longer necessary because its use is “green” pricing—an alternative to electric utility

goals have already been achieved—i.e., cogeneration funding of renewable energy projects (see inset below).

using improved turbine techniques and the use of

renewable resources has not only gotten a foothold but In addition to PURPA's merits regarding the envihas claimed a rather significant share of electric power ronment and fuel diversification, its supporters point out

production. Proponents of repeal further contend that that QFs bring increased reliability while decreasing the

PURPA's environmental and fuel diversification goals need for large, costly plants. In addition, they contend

will be maintained by the workings of a free market. that today's utilities have too much market power, which

Others are not so sure. While they may agree that a free

market can provide a solution to many of the industry's

problems, they seriously question the wisdom of relying

on competition to continue the strides made in the use of

renewables and cogeneration techniques. Currently, 79

percent of 1995 nonutility capacity and 57 percent of

planned additions from 1996 through 1999 are PURPA

QF facilities. Energy conservation and diversification of

generating fuels were mandated by Congress because of

our dependence on foreign oil and the Nation's feeling of

helplessness as a result of 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 possibility 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 fervently stress that common

sense dictates that energy be conserved and that Several legislative proposals pending before the 104th

electricity generation use more environmentally benign Congress were considered comprehensive energy refuels in order to sustain a certain quality of life for future structuring bills. In addition to PUHCA and PURPA

generations. In addition, some believe that QF policy repeal or reform, they dealt with multiple restructuring 66

corrects a market failure—i.e., the price of fossil or issues, such as stranded cost recovery, mergers, market

nuclear energy is too low based on the costly damage it power, and divestiture of utility assets. These bills were

does to the environment and the fact that those who aimed at providing a national focus for the electric power

create the pollution do not pay for it. In this context, industry's competitive evolution. There are strong arguconservation, diversification of fuels, and the use of ments both for and against this type of legislation. Suprenewable resources that are not depletable and other porters say it remedies the unappealing piecemeal apfuels that lessen the problems of acid rain and proach of dealing with the critical issues that have

greenhouse gases must continue to be supported. (For appeared and will continue to appear during the

example, in the past, California encouraged the transition. Opponents contend that it is not wise to rush

development of renewable generating technologies into such uncharted territory, but rather that we should

through PURPA by having two-tiered avoided cost for deal with each issue as it arises. Following is a brief

QFs—one for fossil-fueled plants and another for summary of the content of each bill.

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 and probably would be warranted in a competitive electricity supply scenario, we are not there yet.

Just as some PUHCA reformers are against immediate

piecemeal and standalone 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 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.

Proposed Comprehensive 

Energy Restructuring Bills
44 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Green Pricing

Utilities can encourage the development of renewable energy through “green pricing” programs for residential, commercial, and industrial

consumers, and at the same time measure support for renewables under competitive conditions. These programs offer a potential market a

solution to the funding of future renewable technologies, in which electricity consumers would voluntarily pay for renewable energy

development. For instance, consumers willing to pay a price premium for renewable energy could do so by participating in a program

that allows them to add some incremental amount of money to their regular electricity bills or another program which rounds up

consumers’ bills to the nearest dollar, with the added quantity going to support renewable energy. According to the Natural Resources b

Defense Council, power generated today through green pricing programs in the United States is nearly 2 megawatts. In a competitive c

environment, however, there is a question of the degree of impact there will be on renewable development if green pricing program

participants choose another electricity supplier.

To date, approximately 10 utilities have introduced green pricing programs: d

 Public Service Co. of Colorado (PSCO1). The Renewable Energy Trust (RET) Program supports the accelerated growth of

renewable generation construction through voluntary monthly pledges.

 Public Service Co. of Colorado (PSCO2). The RET Round-Up Program rounds customers’ monthly bills up to the nearest dollar

to support renewable electric generation.

 Wisconsin Public Service Corp. (WPS). The SolarWise for Schools Program collects monthly pledges to support the construction

of photovoltaic systems on high-school rooftops.

 Gainesville Regional Utilities (GRU). Monthly pledges or one-time donations support a photovoltaic electric generation system.

 Sacramento Municipal Utility District (SMUD). The PV Pioneers Program installs photovoltaic systems on consumers’ roofs for

a $4.00 monthly premium. Participation has been restricted by the utility.

 Traverse City Light and Power (TCLP). The Green Rate Wind Project supplies consumers with electricity from a 600-kW wind

turbine for 8.3 cents/kWh (a 1.58 cent/kWh premium). Subscriptions last for 3 years. The program received the American Public

Power Association’s ENERGY Innovator of the Year award in 1995.

 Detroit Edison (DE). The SolarCurrents Program allows consumers to purchase a share of capacity in a photovoltaic system at

a net monthly cost of approximately $6.59 for each 100-watt increment. The typical participant purchases 150 watts. Participation

has been restricted by the utility.

 Niagara Mohawk Power Corp. (NM). The GreenChoice Program charges a fixed premium of $6.00 per month. Five-sixths of the

net funds are spent on renewable energy projects, and one-sixth is spent on tree planting.

 Northern States Power (NSP). The Solar Advantage Program chose 17 of 250 residential consumers who were willing to pay $50

per month to have a 2 kW photovoltaic system installed on their rooftops. NSP pays for, installs, and maintains the system and participants must sign up for 5 years. At the end of that time, customers have three options: (1) sign another 5-year contract, at the end

of which they may purchase the system for $1; (2) purchase the system from NSP for $3,000; or (3) have NSP remove the system.

 Wisconsin Electric Power Company (WEPCO). WEPCO gives customers the option of purchasing 100, 50, or 25 percent of their

electricity at an additional rate of 2.04 cents per kWh from hydro dams operated by Manitoba Hydro and Ontario Hydro and a

Minnesota Power & Light biomass plant that burns wood pulp that would otherwise go in a landfill. A customer with a $40 monthly

bill will pay a premium of $12, $6, or $3 depending on the level chosen.

“NRDC Analysis Finds Green Pricing Programs Total Less Than 2 MW,” Utility Environment Report (April 12, 1996), p. 14. a

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

and B. Byrnes, M. Rahimzadeh, R. de Alba, and K. Baugh, “Green Pricing: The Bigger Picture,” Public Utilities Fortnightly (August 1996),

pp. 18-19.

In the past, green pricing programs have targeted the residential consumer, but now commercial and industrial consumers have shown c

interest. The green pricing programs available for commercial and industrial consumers are not the same, in many cases, as those offered

to residential consumers.

The first eight of the following descriptions are reproduced from B. Byrnes, M. Rahimzadeh, R. de Alba, and K. Baugh, “Green Pricing: d

The Bigger Picture,” Public Utilities Fortnightly (August 1996), p. 20. For additional information, refer to B. Byrnes, M. Rahimzadeh, R.

de Alba, and K. Baugh, “Green Pricing: Removing the Guesswork,” Public Utilities Fortnightly (August 1995), pp. 26-28. The last two

descriptions are excerpted from a fact sheet provided by the Regulatory Assistance Project in Gardiner, ME.
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 45

S. 1526, “Electricity Competition Act of H.R. 3782, “Electric Power Competition and

1996” Consumer Choice Act of 1996”

This bill, introduced into the Senate by Senator J. Bennett

Johnston (D-LA) on January 25, 1996, would require

States to conduct proceedings to examine their local

power markets and either set up competitive wholesale

procurement markets, establish retail access programs for

all consumers, or devise their own programs as long as

they do not allow utilities to unduly favor their own

generation and do not subject consumers to abovemarket energy costs. (Utilities not regulated by FERC or

the States must conduct similar proceedings on their

own.) State plans would have to be in effect 18 months

after enactment of the legislation. States that choose

retail wheeling must have it in place by 2002. Otherwise,

retail wheeling for all must be in effect by 2010—a date

that is subject to change, depending on the consensus of

the industry. In exchange, utilities would be able to

collect all their legitimate, verifiable, and prudently

incurred stranded costs. On the retail level, those costs

would be determined by the States, with guidance by

FERC. And if the States do not give the utilities full

recovery of those costs, the utilities may take their cases

to FERC.

H.R. 2929, “Electric Power Competition Act

of 1996”

Introduced into the House of Representatives by

Congressman Edward J. Markey (D-MA) on February 1,

1996, this bill would provide incentives for State

regulated utilities and regulatory commissions to remove

barriers to effective competition in the electricity industry. The bill would remove the mandatory purchase

obligation of PURPA in those instances where the State

commission certified that the utility met specific competition standards. It also provides for States to promote

renewable energy resources and would protect existing

contracts under PURPA. In addition, it would remove

the “State action” exemption from Federal anti-trust

statutes where utilities were subject to effective competition in electricity generation. Title I would suspend

application of PURPA if an electric utility receives a

certification of competition from its State regulatory commission. In addition, it would preserve existing PURPA

contracts between utilities and QFs and would expressly

permit a State to favor particular types of generation

(e.g., renewables) in determining avoided cost under

PURPA. Title II would establish Federal standards for This bill, introduced into the House of Representatives on

utilities in order to receive a certification of competition July 11, 1996, by Congressman Dan Schaefer (R-CO),

from a State regulatory authority. would give all consumers of electricity the right to choose

This companion bill to H.R. 2929 was introduced into the

House of Representatives by Congressman Edward J.

Markey (D-MA) on July 11, 1996. This bill is aimed at

promoting competition in the electric utility industry and

would link any repeal of PUHCA to State action to

introduce full retail competition in electricity generation.

In addition, it is aimed at addressing the risks that

electric utility mergers, utility market power, or utility diversification into new lines of business might harm

electricity consumers or undermine the emergence of a

fully competitive electricity generation market. In

general, it would:

 Require each State to initiate a retail competition

rulemaking proceeding pursuant to certain Federal

standards

 Repeal PUHCA for those electric utility holding

companies whose service territories have been

opened up to full retail competition and have met

minimum standards for renewables, efficiency, and

low-income consumer protections

 Give FERC and the States enhanced authority to

regulate utility mergers and acquisitions to protect

consumers from transactions that are inconsistent

with effective competition in electricity markets or

would increase electricity prices

 Give FERC and the States authority to regulate

utility market power to guard against anticompetitive practices

 Grant FERC and the States authority over electric

utility interaffiliate transactions to guard against

cross-subsidization or self-dealing

 Direct FERC to establish regional transmission

markets to assure functionally efficient and nondiscriminatory transmission and prevent “pancaking” of rates

 Assure that FERC and State regulators have full

access to electric utility books and records.

H.R. 3790, “Electricity Consumers' Power

to Choose Act of 1996”
46 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

H.R. 3172, “The Clean Power Production Act,” Section 2(3) (introduced March 27, 1996). 67

Ibid. 68

among competitive suppliers of electricity services no strategies and policies to mitigate the environmental imlater than December 15, 2000. It would also repeal both pacts associated with electric utility restructuring. AlPUHCA and PURPA. In addition, it would establish a though it does not address proposals concerning how to

national renewable energy credit trading system to restructure or deregulate the industry, it is salient in that

encourage development of electricity generated from it proposes a means of ensuring that there will be no sigrenewable energy sources, specifying that all generators nificant diminution in the quality of the national and

of electricity selling power are to have renewable energy global environment as a consequence of restructuring. It

credits equal to 2 percent of their generation—increasing states that “the opportunities for increased competition

to 4 percent by the year 2010. According to a news item offer potentially significant economic benefits to all

released simultaneously with introduction of this bill, classes of consumers; however, there remains a substan-

“There is not a single mandate on states in this bill. State tial risk of increased emissions and environmental dammunicipalities and rural cooperatives will have full ages due to changed operating procedures and market

discretion to decide whether or not to implement retail characteristics among electricity utility generators.” In

choice for their ratepayers by the date certain. If they addition, it points out that, while “there have been a

decide not to implement retail choice for their citizens, number of proposals among States for mitigating the enFERC is directed to do so for them.” vironmental impacts of electric utility restructuring

H.R. 4297, “Consumers Electric Power Act”

This bill, introduced by House Majority Whip Tom

DeLay (R-TX) on September 28, 1996, would guarantee

that all consumers have the right to choose their

electricity service provider by January 1, 1998, and

would ensure that providers are allowed to compete on

a level playing field. The legislation would preserve and

strengthen State authority with regard to universal

service for consumers, universal access for providers,

conservation programs, and future economic development programs. In addition, it would outline the

performance objectives of transmission and distribution

systems in a competitive environment. After competition

is affirmatively achieved, the proposal would prospectively repeal PUHCA and PURPA.

In the Planning Stages

According to an article in Electric Utility Week on

September 23, 1996, Senator Dale Bumpers (D-Ark) “has

ordered his staff to begin crafting comprehensive

legislation to restructure the electric industry.” Details or

a framework for the planned legislative proposal may be

available by the end of this year.

Other Relevant Legislation

H.R. 3172, “Clean Power Production Act”

Introduced by Congressman Patrick J. Kennedy (D-RI)

into the House of Representatives on March 27, 1996, this

bill proposed establishment of a commission to develop

67

. . . no regional or national mitigating strategies and

policies have been developed or implemented.”68

The proposed legislation calls for the Administrator of

the Environmental Protection Agency (EPA) to undertake and submit within 6 months an assessment of environmental impacts associated with restructuring and, in

doing so, to consult with the Secretary of Energy, the

Chair of FERC, the Chair of the Council on Environmental Quality, and other Federal and State agency

officials as appropriate. The EPA Administrator and the

Secretary of Energy would then establish and co-chair

the Commission for Environmental Mitigation of Electric

Utility Restructuring, which would include representatives from the Council on Environmental Quality, FERC,

and the Council of Economic Advisors. Using the aforementioned assessment, the Commission would develop

strategies and policies to mitigate the environmental impacts associated with electric utility restructuring.

Within 12 months after enactment of the Act, the Commission would submit a report to Congress containing

the recommendations for strategies and policies.

H.R. 4316 ( Not Yet Titled)

This bill was introduced by Congressman Frank Pallone

(D-NJ) into the House of Representatives on September

28, 1996. It would amend the Federal Power Act to

provide a moratorium on the retail wheeling of electric

energy until the Clean Air Act is amended to reduce

significantly certain transboundary air pollution associated with ozone and ozone precursors, PM-10,

mercury, and carbon dioxide. It stipulates that neither

FERC nor any State may permit any person to enter into

an arrangement for the sale of electric energy in
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 47

The National Council on Competition and the Electric Industry is a joint project of the National Association of Regulatory Commissioners and the 69

National Conference of State Legislatures. Members include the Department of Energy and the Environmental Protection Agency. The Council has

commissioned a series of papers to provide information regarding the complex issues surrounding competition in the electricity industry. For further

information surrounding the tax issue, refer to the first paper in their series, Federal, State and Local Tax Implications of Electric Industry Restructuring.

Their subsequent papers include Assessing Impacts of Restructuring on Small-Business, Residential and Low-Income Customers; The Unintended Impacts

of Restructuring; The Organization of Competitive Wholesale Power Markets and Spot Price Pools; Stranded Benefits in Electric Utilities Restructuring;

The British Electric Utility Restructuring Experience: History and Lessons for the United States; and their forthcoming paper, Regulation and Competition

Without Privatization: Norway's Experience.

D. Chmielewski, “Darker Side of Utility Deregulation: Lost Taxes,” The Patriot Ledger (February 28, 1996), p. 10. 70

National Council on Competition and the Electric Industry, Federal, State and Local Tax Implications of Electric Utility Industry Restructuring 71

(Dallas, TX: Deloitte & Touche LLP, October 1996), p. xi.

state commerce to a retail electric consumer located provide for a transition to market-based rates for such

within the exclusive service territory of a State-regulated power. H.R. 310, the Federal Power Administration

or nonregulated electric utility serving retail consumers Privatization Act of 1995, introduced by Congressman

in that State. Scott Klug (R-WI) on January 4, 1995, directed the

Public Law 104-58, “Alaska Power

Administration Asset Sale and Termination

Act”

The idea of the Federal Government removing itself from

the electricity business by selling off its power marketing

administrations (PMAs) has recently reappeared. There

are five such Federal PMAs: The Alaska Power Administration, the Southeastern Power Administration, the

Southwestern Power Administration, the Western Area

Power Administration, and the Bonneville Power

Administration. The marketing and transmission of

electric power produced at Federal hydroelectric projects

and reservoirs is carried out by the PMAs, which are

under the jurisdiction of the Department of Energy. One

law has already been enacted—the Alaska Power

Administration Asset Sale and Termination Act, passed

on November 28, 1995. It authorized and directed the

Secretary of Energy to sell the Alaska Power

Administration, which is composed of the Eklutna

Hydroelectric Project and the Snettisham Hydroelectric

Project. Proceeds from the sale were to be deposited in

the Treasury of the United States to the credit of

miscellaneous receipts. It also authorized the export of

Alaska North Slope crude oil. 

Other Federal PMA Privatization Proposals

Other legislative proposals related to the abovementioned Act have been drafted and will be debated in

Congress. H.R. 1801, the Federal Power Asset

Privatization Act of 1995, introduced by Congressman

Mark A. Foley (R-FL) on June 5, 1995, would privatize

certain Federal power generation and transmission

assets. H.R. 3878, introduced by Congressman Gary

Franks (R-CT) on July 23, 1996, would privatize the

Federal PMAs and certain facilities of the Tennessee

Valley Authority (TVA) and, in the interim, would

President to develop a plan for selling all of TVA’s assets

and offered an amendment to the energy and water

appropriations bill to kill the $103 million TVA Federal

subsidy. The subsidy bill did not reach the floor, and the

TVA sale bill failed in a House vote, 144 to 248.

Relevant Tax Issues

While no legislative proposals have been made as yet

that would specifically address Federal income tax rules

that affect only electric utilities, such legislation may be

forthcoming in light of the industry's move to a

competitive environment. According to the National

Council on Competition and the Electric Industry,69

competition will undoubtedly have a major impact on

Federal, State, and local tax structures. 

Electric utilities pay gross receipts taxes, net income

taxes, property taxes, and franchise fees to their

respective State and local governments. If electricity

prices and utility property values decrease as a result of

competition, cities could lose millions of dollars in tax

revenues. One study by the Massachusetts Alliance of

Utility Unions stated that “deregulation jeopardizes $87

million in tax revenues for 82 cities and towns in Eastern

Massachusetts.”70

Utilities also collect sales and use taxes and utility user

taxes from their customers and, in turn, remit them to the

proper taxing authority. Under competition, these “taxes

that have been passed through to customers as higher

electricity rates will be borne to an increasing extent by

the utilities themselves and will affect who provides

electricity and where it is generated.” 71

At the Federal level, utilities currently receive two tax

benefits—accelerated depreciation and the investment

tax credit—because they are regulated on a cost-ofservice basis. This regulation also means that income tax

expenses are calculated and charged to consumers in
48 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Ibid., pp. xi-xii. 72

H. J. Eurich, “Nuveen: New U.S. Rules Could Help, Hurt Utilities and Localities,” The Bond Buyer (September 26, 1996), p. 5. For more information, 73

refer to M. M. Canan, “As Public Power Faces Competition, Effects on Bonds Unclear,” The Bond Buyer (March 29, 1996), p. 5, and M. M. Canan,

“Utilities’ Use of Tax-Exempts Requires Review, Clinton Says,” The Bond Buyer (February 20, 1996), p. 1.

their rates. Under deregulation, these Federal tax rules reciprocity condition stated in FERC Order 888. The

will have to be readdressed by policymakers. Also, the extra money (debt) required could influence the utility’s

rules concerning the current deduction for the funding of creditworthiness. Also, utilities “could lose their taxnuclear decommissioning may have to be revised. Other exempt status by deriving more than 10 percent of their

tax-related issues that will have to be taken into account revenues from power sales and/or transmission rights to

are “the timing and amount of any tax return deductions private utilities.”

for utility property made uneconomic under market conditions . . . [and the fact that] . . . the use of a publicly All of the proposals mentioned in this chapter are

owned utility's transmission system for the benefit of summarized in Table 4, which is provided as a quick

third parties may jeopardize the tax-exempt status of its reference to recently introduced legislation dealing with

bonds. . . .” While access to more transmission lines the changing structure of the electric power industry. A 72

could expand a municipal utility’s consumer base by al- detailed discussion of the Federal role, as well as the role

lowing entrance to a wider region, the utility may be or- of State governments, in promoting competition in the

dered to increase its own transmission line network to industry is presented in the following chapter.

adapt to the needs of other power companies to satisfy a

73
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 49

Table 4. Proposed Legislation Influencing the Restructuring of the Electric Power Industry Introduced

During the 104th Congress

Bill Purpose/Sponsor

H.R. 310

"Federal Power Administration

Privatization Act of 1995"

To provide for the privatization of the Federal Power Marketing Administrations, and

for other purposes.

Introduced by Representative Scott Klug (R-WI) on January 4, 1995, and referred to

the Subcommittee on Water and Power Resources.

S. 299

"A Bill to Amend the Federal Power

Act"

To amend the Federal Power Act to modify an exemption relating to the territory for

the sale of electric power of certain electric transmission systems, and for other

purposes.

Introduced by Senator Thad Cochran (R-MS) on January 31, 1995, and referred to

Subcommittee on Energy Production and Regulation.

S.708

“Electric Utility Rate Payer Act”

To repeal Section 210 of the Public Utility Regulatory Policies Act of 1978.

Introduced by Senator Don Nickles (R-OK) on April 6, 1995, and referred to the

Senate Committee on Energy and Natural Resources.

H.J. RES. 178

(No title)

A joint resolution disapproving Orders Nos. 888 and 889 of the Federal Energy

Regulatory Commission.

Introduced by Representative Mark Foley (R-FL) on June 8, 1995, and referred to the

Subcommittee on Energy and Power.

H.R. 1801

"Federal Power Asset Privatization

Act of 1995"

To privatize certain Federal power generation and transmission assets, and for other

purposes.

Introduced by Representative Mark A. Foley (R-FL) on June 8, 1995, and referred to

the Subcommittee on Water and Power Resources.

S.1317

“Public Utility Holding Company Act

of 1995”

To repeal the Public Utility Holding Company Act of 1935, to enact the Public Utility

Holding Company Act of 1995, and for other purposes.

Introduced by Senator Alfonse M. D'Amato (R-NY) on October 12, 1995.

H.R.2562

“Ratepayer Protection Act”

To repeal Section 210 of the Public Utility Regulatory Policies Act of 1978.

Introduced by Representative Cliff Stearns (R-FL) on October 31, 1995, and referred

to the House Committee on Commerce.

S.1526

“Electricity Competition Act of

1996”

To provide for retail competition among electric energy suppliers, to provide for

recovery of stranded costs attributable to an open access electricity market, and for

other purposes.

Introduced by Senator J. Bennett Johnston (D-LA) on January 25, 1996, and referred

to the Senate Energy and Natural Resources Committee.

H.R.2929

“Electric Power Competition Act of

1996”

To amend Title I of the Public Utility Regulatory Policies Act of 1978 to deregulate the

electric power industry.

Introduced by Representative Edward J. Markey (D-MA) on February 1, 1996, and

referred to the House Committee on Commerce and to the House Committee on the

Judiciary.

H.R.3172

“Clean Power Production Act”

To establish a Commission to develop strategies and policies to mitigate the

environmental impacts associated with electric utility restructuring.

Introduced by Representative Patrick J. Kennedy (D-RI) on March 27, 1996, and

referred to the House Committee on Commerce.
Table 4. Proposed Legislation Influencing the Restructuring of the Electric Power Industry Introduced

During the 104th Congress (Continued)

Bill Purpose/Sponsor

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

H.R. 3601

"Public Utility Holding Company Act

of 1996"

To repeal the Public Utility Holding Company Act of 1935, to enact the Public Utility

Holding Act of 1996, and to amend the Federal Power Act to repeal its conflict of

jurisdiction guidelines.

Introduced by Representative W.J. (Billy) Tauzin (R-LA) on June 6, 1996, and

referred to the Subcommittee on Energy and Power.

H.R.3782

“Electric Power Competition and

Consumer Choice Act of 1996”

Introduced by Representative Edward J. Markey (D-MA) on July 11, 1996, and

To modernize the Public Utility Holding Company Act, the Federal Power Act, and the

Public Utility Regulatory Policies Act of 1978 to promote competition in the electric

power industry.

referred to the House Committee on Commerce; companion bill to H.R. 2929.

H.R.3790

“Electricity Consumers' Power to

Choose Act of 1996”

To give all American electricity consumers the right to choose among competitive

providers of electricity, in order to secure lower electricity rates, higher quality

services, and a more robust U.S. economy, and for other purposes.

Introduced by Representative Dan Schaefer (R-CO) on July 11, l996, and referred to

the House Committee on Commerce.

H.R. 3878

"Power Marketing Administration

Privatization and Reform Act of

1996"

To privatize the Federal Power Marketing Administrations and certain facilities of the

Tennessee Valley Authority and, in the interim to provide for a transition to marketbased rates for such power, and for other purposes.

Introduced by Representative Gary Franks (R-CT) on July 23, 1996, and referred to

the Subcommittee on Water and Power Resources.

H.R. 4297

"Consumers Electric Power Act"

To give all American electricity consumers the right to choose among competitive

providers of electricity in order to secure lower electricity rates, higher quality

services, and a more robust U.S. economy, and for other purposes.

Introduced by Representative Tom DeLay (R-TX) on September 28, 1996, and

referred to the House Committee on Commerce.

H.R. 4316

(Not yet titled)

To amend the Federal Power Act to provide a moratorium on the retail wheeling of

electric energy until the Clean Air Act is amended to reduce significantly certain

transboundary air pollution, and for other purposes.

Introduced by Representative Frank Pallone (D-NJ) on September 28, 1996, and

referred to the House Committee on Commerce.

 Note: At the end of every session of Congress, if a bill does not become a law, it must be reintroduced during the next session for

consideration. The proposed legislation introduced during the 104th Congress contained in this table may or may not be reintroduced

into the 105th Congress as is. A bill may be reintroduced with major revisions, or the legislation may become part of another bill.

 Source: Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels.
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 51

Title VII of EPACT (Electricity) is reproduced in Appendix F. 74

EPACT provisions prohibit FERC from issuing orders that are inconsistent with any State law which exclusively governs the retail marketing areas 75

of the electric utilities.

A firm’s opportunity cost of producing a good is the best alternative that the firm foregoes to produce it. Equivalently, opportunity cost is the firm’s 76

best alternative use for the factors of production employed to produce the good.

In its Mega-NOPR (see below), FERC points out that new generation facilities can produce power on the grid at a cost of 3 to 5 cents per kWh, yet 77

the costs for large plants constructed and installed over the last decade were 4 to 7 cents per kWh for coal plants and 9 to 15 cents for nuclear plants. 

For additional details refer to Initial Comments of Edison Electric Institute before the Federal Energy Regulatory Commission, Docket RM94-7-000, 78

filed on December 9, 1994.

Charles G. Stalon, ”An Assessment of the Electric Industry Restructuring Debate,” paper presented at Transportation and Public Utility Group, 79

American Economic Association (New Orleans, LA, January 1992).

Federal Energy Regulatory Commission, The Transmission Task Force's Report to the Commission—Electricity Transmission: Realities, Theory 80

and Policy Alternatives (Washington, DC, October 1989).

Generally speaking, four different types of entities seek access to the grid. These are retail consumers, integrated utilities, wholesale consumers, and 81

captive independent suppliers. Federal Energy Regulatory Commission, The Transmission Task Force's Report to the Commission (Washington, DC,

October 1989), p. 31.

Note that PURPA's intent to facilitate increased diversity in power generation, to foster increased usage of renewable technologies, and to reduce 82

consumption of oil and gas is viewed only as a “qualified success” and not an unqualified one. U.S. Congress, Subcommittee on Energy and Power of the

Committee on Commerce, Oversight Hearings on the Public Utility Regulatory Policies Act and Its Role in the Increasingly Competitive Electricity Markets

(104th Congress, Second Session, February 1996), p. 13.

7. Evolving Regulatory Reform:

The Federal and State Role in Promoting Competition 

This chapter provides information about measures designed primarily to encourage the electric power

initiated at the Federal and State levels to promote industry to rely increasingly on market forces instead of

competition in the domestic electricity industry. Because cost-based regulation. As the process gains momentum,

changes are taking place rapidly at the State level, the efficiency and welfare gains should result.

information concerning them is for the period ended June

30, 1996.

The Energy Policy Act of 1992 (EPACT) overhauled

provisions of the Federal Power Act (FPA) governing

availability of transmission services to other producers by

instructing the Federal Energy Regulatory Commission

(FERC) to order wholesale wheeling of electricity if such

an order does not violate State laws or affect reliability

(Section 721, Title VII - Electricity, Subtitle B - Federal

Power Act: Interstate Commerce in Electricity). For this

objective to be achieved, EPACT expanded FERC's

authority in Section 211 of the FPA to order transmission

services upon application.74

EPACT also authorized FERC to set transmission rates at mission issues, released in 1989, concluded that availlevels that permit the recovery of all costs incurred in ability of transmission access was essential for a comconnection with the transmission services, including petitive wholesale power market. FERC also conlegitimate, verifiable, and economic costs—subject to the ditioned its approval of certain mergers upon transrequirement that these costs be recovered from the mission access with a view to mitigate anti-competitive

applicant (seeking transmission services) and not from the effects. In some other cases, FERC allowed customers to

transmitting utilities' existing customers. This provision gain access to transmission services to reach competing 75

protects the utilities’ existing customers (or “native load” suppliers. These actions supported the trend to promote

customers) and opens the way for opportunity cost wholesale competition initiated by the passage of the

pricing. EPACT's provisions pertaining to electricity are Public Utility Regulatory Policies Act (PURPA) in 1978. 76

77

FERC's Role in Promoting

Competition in Wholesale Power 

Even before the passage of EPACT in 1992, FERC played

a critical role in the competitive transformation of wholesale power generation in the electric power industry.78

Specific initiatives include notices of proposed rulemaking

(NOPRs) issued in 1988 that proposed steps toward the

expansion of competitive wholesale electricity markets.

Even though FERC withdrew these NOPRs in 1990, the

underlying interest at FERC in promoting competition

was evident. A task force report dealing with trans- 79

80

81

82
52 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

These proceedings include: (1) Stranded Cost NOPR, Docket No. RM94-7-000 (June 6, 1994), (2) Transmission Pricing Policy Statement, Docket 83

No. RM93-19-000 (October 26, 1994), (3) Pooling Notice of Inquiry, Docket No. RM94-20-000 (October 26, 1994), (4) Regional Transmission Group (RTG)

Policy Statement, Docket No. RM93-3-000 (July 30, 1993), and (5) Notice of Inquiry on Merger Policy, Docket No. RM96-6-000 (January 31, 1996).

Federal Energy Regulatory Commission, Docket No. RM94-7-000, Recovery of Stranded Costs by Public Utilities and Transmitting Utilities 84

(Washington, DC, June 29, 1994).

Other terms used to describe stranded costs include: uneconomic sunk costs, transition costs, unmarketable costs, strandable costs, and stranded 85

investments.

An unbundled transmission services consumer, as defined in the NOPR, is one who purchases transmission as a product that is separate from the 86

purchase of generation.

Federal Energy Regulatory Commission (FERC), Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Docket No. RM-94-7- 87

000, p. 20. These estimates include both wholesale and retail stranded costs. FERC, however, noted that retail stranded costs may be significantly higher

than the wholesale stranded costs, given that only 10 to 15 percent of generating investment (of the investor-owned utilities) is in the wholesale rate base.

Wholesale power market transactions include purchases, sales for resale, exchanges and wheeling (i.e., transmission services). These transactions 88

may be divided into two broad categories: requirement and coordination transactions. Wholesale requirement contracts involve firm sales of capacity, meaning

that either the associated energy will be taken by the purchaser or the purchaser will pay for the capacity (i.e., the demand charge) when the energy is not

taken. Requirement contracts may involve utilities that have either insufficient or no generating capability to satisfy their customer load. The duration of

sale and the type of capacity sold are key factors in determining the type and value of the transactions. Coordination transactions are for short periods, are

subject to curtailment, and rarely have a capacity charge in the price.

FERC also initiated a number of proceedings in the period to recover all their prudently incurred costs in generating

immediately following the passage of EPACT in 1992. facilities. Based on this possibility, estimates of potential 83

The Commission, with its experience in promoting com- stranded costs vary. Some exceed $200 billion or more.

petition in the natural gas industry, was moved into action These estimates are based, to a large degree, on the

to provide a regulatory framework for dealing with utility difference between the book value of generating assets

assets likely to be stranded during a transition into a com- and their presumed market value.

petitive economy. To address this issue, FERC approved

a proposed rulemaking to provide a regulatory frame- Stranded costs can occur during the transition to a fully

work for dealing with wholesale and retail stranded costs competitive wholesale power market as some wholesale

by public utilities and transmitting utilities. FERC’s customers leave a utility's system to buy power from other

NOPR, entitled “Recovery of Stranded Costs by Public sources. This may idle the utility's existing generating

Utilities and Transmitting Utilities,” issued on June 29, plants, imperil its fuel contracts, and inhibit its capability

1994, sought public comments concerning the issues to undertake planned system expansion leading to the

raised by the proposed rulemaking. creation of “stranded costs.” 84

Defining Wholesale and Retail Stranded

Costs

The NOPR defines wholesale stranded costs as “any 85

legitimate, prudent and verifiable costs incurred by a

public utility or a transmitting utility to provide a service

to a wholesale requirement customer that subsequently

becomes, in whole or in part, an unbundled transmission

services customer of that public utility or transmitting

utility.” Similarly, retail stranded costs are defined as 86

“any legitimate, prudent, and verifiable costs incurred by

a public utility or a transmitting utility to provide a service to a retail franchise customer that subsequently becomes, in whole or in part, an unbundled transmission

services customer of that public utility or transmitting

utility.”

Stranded costs emerge because new generating capacity

can currently be built and operated at costs that are lower

than many utilities' embedded costs. Wholesale and retail

customers have, therefore, an incentive to turn to lower

cost producers. Such actions make it difficult for utilities

87

The Commission noted that during the transition to a fully

competitive wholesale power market, some utilities may

incur stranded costs as customers switch to other

suppliers. If power previously sold to a departing 88

wholesale customer cannot be sold to an alternative buyer,

or if other means of mitigating the stranded costs cannot

be found, the options for recovering stranded costs are

limited. These costs must be recovered from either the departing customer or the remaining customers or borne by

the utility's shareholders. These comments are applicable

with equal force in cases of retail stranded costs.

The Commission recognized that there were three ways in

which stranded costs were most likely to occur as a result

of the transition to the wholesale power market: 

  Wholesale customers leaving the system

  Retail-turned-wholesale customers leaving the

system

  Retail customers leaving the system.
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 53

While the Commission's focus is to look at stranded costs relative to generating capacity, a somewhat broader consideration of stranded costs would 89

include fuel supply costs, purchased power costs, nuclear decommissioning costs, regulatory assets, and other costs that may be stranded.

The NOPR provides guidance concerning the evidentiary demonstration that a public utility or transmitting utility must make to recover stranded 90

costs. These include: (1) a utility must show that it incurred stranded costs based on an expectation that was reasonable when the costs were incurred that

the applicable contract would be extended; (2) a utility must show that the stranded costs it incurred are not more than the customer would have contributed

had the customer remained a wholesale customer of the utility; and (3) a utility must show that it has taken and will take reasonable measures to mitigate

stranded costs.

A public utility is defined as any person who owns or operates facilities subject to the jurisdiction of the Commission. A transmitting utility is defined 91

as any electric utility, qualifying cogeneration facility, qualifying small power production facility, or Federal Power Marketing Agency which owns or operates

electric power transmission facilities which are used for sale of electric energy at wholesale.

Federal Energy Regulatory Commission, Notice of Proposed Rulemaking and Supplemental Notice of Proposed Rulemaking, issued on March 29, 92

1995. The NOPR is made up of two dockets: (1) Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by

Public Utilities, Docket No. RM95-8-000, and (2) Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Docket No. RM94-7-001.

The NOPR contains a detailed recapitulation of the various initiatives taken by the Commission to foster a competitive environment in the handling of bulk

power markets. The narrative includes the Commission's aggressive implementation of Section 211, a new look at undue discrimination under the FPA, easing

of market entry for sellers of electricity from new generation facilities, and the initiation of industry-wide reforms.

Wheeling implies the contracted use of facilities of one or more entities to transmit electricity for another entity. Because not all utilities voluntarily 93

allow this facility to suppliers or purchasers of wholesale power, FERC's open access requirement is designed to ensure that the buyers and sellers have equal

access to the transmission grid. These considerations give rise to the term “mandatory wheeling.” 

In order to alleviate concerns regarding the future First, there may be an impairment of a utility's financial

financial viability of the investor-owned utilities, the Com- capability to continue providing reliable service, depenmission viewed an early consideration of stranded cost ding on the magnitude of stranded costs. Second, permitrecovery as critical to both buyers and sellers of electric ting customers to leave without paying stranded costs

energy and transmission. This emphasis results from the would impose an inequitable burden on captive 89

conceptual underpinnings of the traditional regulatory customers. 

compact, which ensures a utility's financial integrity by

permitting recovery of prudently incurred costs plus a fair

rate of return in exchange for regulation of its franchised

territory and the associated obligation to provide

reasonably priced electricity on demand. In addition, the

Commission contended that the issue of stranded costs

should be resolved in as short a time as possible.

With regard to the recovery of wholesale stranded costs,

the Commission differentiated between existing contracts

(i.e., contracts executed on or before issuance of the

NOPR) and new contracts (i.e., contracts executed after

the publication of the NOPR on July 11, 1994). Recovery

of stranded costs for the latter category could be sought

only if the contract provisions explicitly provided for it.

For existing wholesale requirement contracts that do not

explicitly provide for the recovery of stranded costs, there

would be a 3-year transition period during which the

utilities would attempt to renegotiate these contracts

(including the recovery of stranded costs through transmission rates). State regulatory authorities were expected 90

to deal with the retail stranded cost issues.

Where a conflict may arise between States or within a

State, the Commission may entertain requests toward the

recovery of retail stranded costs. The Commission may,

however, also decide not to entertain any request on this

issue.

Failure to address the stranded cost issue, according to the

Commission, could harm the public interest in two ways.

The Commission's NOPR provides a jurisdictional

analysis in support of the proposed rulemaking to include

wholesale transmission and retail transmission activities.

Based on these considerations, the Commission sought

public comments on amending its regulations concerning

the recovery of wholesale and retail stranded costs by

public and transmitting utilities under Sections 205, 206,

211, and 212 of the Federal Power Act. Comments and 91

reply comments on the proposed rulemaking were invited

within a 60-day and a 90-day period following

publication of the NOPR in the Federal Register.

The Mega-NOPR

With a view to achieving its stated goal of encouraging

lower electricity prices by structuring an orderly transition

to competitive bulk power markets, FERC proposed

additional sweeping changes by releasing what is now

called the “Mega-NOPR.” The Commission stated its 92

twin goals: (1) to facilitate the development of bulk power

markets by ensuring that wholesale purchasers of electric

energy and wholesale sellers of electricity can reach each

other by eliminating anti-competitive practices and undue

discrimination in transmission services and (2) to address

the transition costs associated with the development of

competitive wholesale markets. Thus, the most critical

element is the issue of open access to transmission

facilities or what is commonly known as “mandatory

wheeling” of electric power on nondiscriminatory terms.93
54 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

These rules were proposed by the Commission pursuant to its authority under Sections 205 and 206 of the Federal Power Act. Note that Section 94

206 applies primarily to public utilities. Since not all transmitting utilities are public utilities, the Commission invoked the application of Section 211 of the

FPA as an additional means of promoting increased competition. The Mega-NOPR provides a detailed explanation with regard to the applicability of

provisions of the FPA as relevant to the promotion of competition.

The layout of an electrical distribution system is called a “grid.” 95

Ancillary services are those services necessary to support the transmission of electric power from seller to purchaser. These services range from 96

actions taken to effect the transaction (such as scheduling and dispatching services) to services that are necessary to maintain the integrity of the transmission

system (such as load following, reactive power support, and system protection services). Ancillary services are also needed to correct for effects associated

with undertaking a transaction (such as loss compensation and energy imbalance services).

The term “functional unbundling” implies that rates for transmission and ancillary services be stated in the open access tariff. Thus, a customer who 97

buys both generation and transmission services should have separately stated rates for generation, transmission, and ancillary services on a nondiscriminatory

basis; i.e., the utility should charge itself the same price for these services that other customers will have to pay. The Commission recognized that proposed

unbundling may lead to two separate arrangements: one for wholesale transactions under its jurisdiction and the other for retail transactions governed by

a State regulatory body. Currently, investor-owned utilities control all three functions under one corporate ownership. While these functions could be

separated and placed under the control of different entities, FERC did not mandate such separations.

The Commission pointed out that dominance of market power leads to discriminatory treatment in various ways, such as network service, pricing, 98

service priority, scheduling, or offering inferior ancillary services. Such discriminatory practices produce market distortions and undermine the goal of creating

competitive bulk power markets. 

Functional unbundling means three things: (1) A public utility must obtain transmission services, including ancillary services, for all of its new 99

wholesale sales and purchases of electric energy under the same tariff with which it covers such services to others. (2) A transmission owner's tariff must

include separately stated rates for transmission and ancillary service components. (3) A public utility must rely on the same electronic network that its

consumers use to obtain transmission information about its system when buying or selling power. Meeting the above requirements will result in two separate

arrangements: an explicit wholesale transmission tariff filed with the Commission and an implicit retail transmission tariff governed by the State regulatory

body.

In addition to the recovery of existing “uneconomic costs” primarily in generation, other transition costs (like fuel supply costs; purchased power costs, 100

including QF costs; nuclear decommissioning costs; regulatory assets; and other utility obligations) are also included in the broader definition of stranded

costs. Costs of certain social programs may also be included in this category.

More specifically, under the Commission's proposal: tariffs for their own wholesale sales and purchases of 94

  All utilities under the Commission's jurisdiction quired that utilities “functionally unbundle” their wholewould be required to file nondiscriminatory open sale generation and transmission services without manaccess transmission tariffs, available to all whole- dating the corporate separation of generation, transsale sellers and buyers of electric energy. mission, and distribution functions. 

  The utilities would be required to take service

under the tariffs for their own wholesale sales and

purchases of electric energy.

  The utilities would be allowed the opportunity to

recover stranded costs.

In proposing the above rules designed to enable all

electricity producers to have access to the grid on equal

terms, the Commission's initiatives were intended to

induce further growth of competitive market forces in the

electric power industry. Under the proposed rules, the 95

transmission utilities would be required to offer point-topoint and network transmission services, including

ancillary services, to consumers comparable to the service

they provide themselves. Utilities falling under the 96

jurisdiction of the Commission will take service under the

electric energy. Thus, the Commission's proposals re97

The Commission hoped that availability of open access to

all participants would tend to eliminate transmission

market dominance exercised by vertically integrated

electric utilities. On the basis of its experience with 98

respect to the deregulation of the natural gas industry, the

Commission expected that, at a minimum, functional

unbundling of wholesale services would be necessary for

nondiscriminatory open access to be available.99

Recovery of Stranded Costs

In promoting the above transition to a competitive bulk

power market, the Commission also recognized that

utilities may not be willing participants in the absence of

assurance concerning the recovery of stranded costs or

investments. Accordingly, the Commission established 100

the principle that utilities are entitled to a full recovery of
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 55

The Commission reiterated its earlier definition of the “wholesale stranded cost” as “any legitimate, prudent and verifiable cost incurred by a public 101

utility or a transmitting utility to provide service to: (1) a wholesale requirements customer that subsequently becomes, in whole or in part, an unbundled

wholesale transmission services customer of such public utility or transmitting utility, or (2) a retail customer or a newly created wholesale power sales

customer, that subsequently becomes, in whole or in part, an unbundled wholesale transmission services customer of such public utility or transmitting utility.”

In providing this definition, the Commission additionally sought comments with regard to the inclusion of stranded costs resulting from unbundled wholesale

transmission for newly created wholesale customers.

New wholesale requirements contracts are those that were executed after July 11, 1994. Existing wholesale power sales contracts are those executed 102

on or prior to this date.

The initial Stranded Cost NOPR proposed a 3-year transition period during which the utilities must attempt to renegotiate existing wholesale contracts 103

that do not contain explicit provisions for stranded cost recovery. While reaffirming the need to renegotiate, the public utility or the customer could file a

proposed stranded cost amendment prior to the expiration of the contracts not mutually renegotiated.

Municipalization refers to the process by which municipalities, currently served at retail by existing utilities (whether they be investor-owned, 104

government-owned, or cooperatives), form municipal utilities of their own and buy power from the wholesale market. For additional information, refer to

Coopers and Lybrand, Electric Municipalization Review, 1996 (Philadelphia, PA, May 1996).

The NOPR does take into account the arguments that stranded cost recovery would inhibit the movement toward competition, distort price signals, 105

result in inefficient decisionmaking, and unfairly reward the least efficient utilities (like those with uneconomical nuclear power plants). To counter these

arguments, the NOPR provides an explanation of why the recovery of legitimate stranded costs is critical to the transition process. 

The utilities in their comments distinguish between marketable and unmarketable stranded costs and maintain that mitigation strategies could not 106

be applied to unmarketable stranded costs. Environmental cleanup costs, decommissioning costs, and regulatory assets are examples of unmarketable

stranded costs, in contrast with stranded capacity, which is marketable. 

legitimate, prudent, and verifiable stranded costs at both The Commission noted that the recovery of stranded costs

the State and Federal levels. is critical to the successful transition of a monopolistic 101

While maintaining that the approach initially proposed by

the Commission (in its Stranded Cost NOPR of June 29,

1994) would adequately cover most costs that could be

stranded due to the adoption of the Open Access NOPR,

the Commission nevertheless made several preliminary

determinations based on a review of the comments

received:

  That recovery of legitimate and verifiable stranded

costs should be allowed and that direct assignment

of stranded costs to departing consumers would be

the appropriate method for recovery in conformity

with the cost causation principle

  That recovery of stranded costs associated with

new wholesale requirements contracts should be

allowed if explicitly provided for in the contract102

  That recovery of stranded costs should be allowed

where existing wholesale requirements contracts

are not renewed and do not contain exit fees or

other stranded cost provisions but the seller is able

to demonstrate that it had a “reasonable expectation” with regard to the renewal of the contract103

  That the States are expected to deal with stranded

costs caused by retail wheeling, with the Commission stepping in only in cases where the State reglatory body lacks authority to address these issues

  That the Commission will provide mechanisms for

stranded cost recovery due to municipalization or According to the Commission, recoverable wholesale

where retail consumers become wholesale cus- stranded costs could best be calculated by the “revenues

tomers. lost” approach, which encompasses mitigation measures 104

industry regulated on a cost-of-service basis to an openaccess, competitively priced industry that will lower

electricity prices. Failure to deal with this issue would 105

merely delay and complicate the proposed industry

transition. As an example, if the industry's shareholders

were to shoulder the burden of stranded costs, the

stability of the industry would be jeopardized. Since the

rules under which the industry operated in the past are

being radically altered, equity demands that utilities be

allowed to recover prudently incurred costs. 

The onus of identifying recoverable wholesale stranded

costs rests on utilities. They are obligated to show that the

stranded costs are not more than what the customer

would have contributed in the event of not leaving the

system. Within this framework, the utilities and customers both have some flexibility with regard to the

period over which stranded cost liability would be

determined. 

Recovery of stranded costs is linked with the critical

requirement that utilities take reasonable and prudent

measures to mitigate stranded costs. FERC's initial

Stranded Cost NOPR (June 1994) lists mitigation options

that include marketing assets or giving the customer the

option to market the generating capacity or supply of fuel

or purchased power that forms the basis for the stranded

cost charge. Any savings resulting from mitigation efforts

are required to be credited to the account of departing

customers.106
56 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

Contributions to revenues attributable to variable costs are to be excluded in adopting the “revenues lost” approach. In addition, the scope of stranded 107

costs was broadened to include other stranded costs, such as fuel supply costs, purchased power costs (including QF costs), nuclear decommissioning costs,

regulatory assets, and other utility obligations. However, the utilities want many more elements to be included, such as construction work in progress,

mandatory social program costs, clean air compliance costs, and others.

Edison Electric Institute and the utilities proposed an asset-by-asset review of stranded investments (including contractual liabilities, regulatory assets, 108

and certain social program costs) and the allocation of these costs among customers to determine a hypothetical cost-of-service measure of stranded cost

liability. Some other commenters (including the American Public Power Association and the Electric Generation Association) advocate adopting a “netting”

approach, in which recoverable stranded costs are the difference between embedded capital costs and the market value of assets. Methodology to compute

stranded costs by using the “revenues lost” approach is described fully in another chapter of this report.

In its initial NOPR on Stranded Costs, the FERC had identified the following: imposing an exit fee prior to, or as a condition of, creating the wholesale 109

entity, or requiring an exit fee before a franchise customer is permitted to obtain unbundled retail wheeling; imposing a surcharge on local distribution rates;

and State condemnation proceedings. Commenters to the NOPR identified several other mechanisms, including: avoiding stranded costs by preserving the

integrity of the franchised service territory; accelerated depreciation to reduce the burden of uneconomic costs; revaluation of assets or adjustment of returns

during transition; adjustment of rates; imposing access fees on new suppliers; tax-based solutions; requiring writeoffs; creating and funding a stranded cost

recovery fund; encouraging end-use efficiency through research and development; and not providing guarantee of service to a departing customer who may

wish to return. 

FERC proposed to establish firm point-to-point transmission charges by applying the fixed-charge methodology. Form 1 data are used to develop 110

the cost relationship between fixed transmission costs and transmission plant investment (a fixed-charge rate). The unit charge is calculated by dividing plant

investment by capability and by multiplying the result by the fixed-charge rate. FERC also suggested an alternative method of computing these charges and

sought comments on which method it should finally adopt for finalizing point-to-point computations. Network transmission charges are derived by using

the load ratio method. Details of the derivation of charges for other services are also provided in the NOPR.

Point-to-point transmission service is the reservation and/or transmission of energy (either on a firm or non-firm basis) from point of receipt to point 111

of delivery, including, where necessary, ancillary service by the transmission provider. Network transmission service (also called network integration

transmission service) allows a transmission customer to integrate, economically dispatch, and regulate its current and planned network resources to serve

its net work load in a manner comparable to that in which the transmission provider utilizes its transmission system to serve its native load customers. These

definitions are derived from FERC's Mega-NOPR.

by reducing the amount of stranded costs recoverable by stranded costs over such services. At the same time, the

a utility by the market price of power that the customer no States also have the authority to address retail stranded

longer takes under its contract. The “revenues lost” ap- costs (or stranded benefits) through their jurisdiction over 107

proach further avoids the asset-by-asset review required facilities used in local distribution. The Commission adby alternative cost-of-service approaches. ditionally provided several indicators to evaluate whether 108

Retail Wheeling and Recovery of Stranded

Costs

In looking at the emergence of stranded costs in retail

trade, the Commission viewed the problem as an exclusive State matter except in cases where the State

regulatory authorities lack authority under State law to

address the issue of stranded cost recovery at the time

retail wheeling is required. The Commission made it clear

that it will not ordinarily allow the States to use the

interstate transmission grid for a pass-through for retail

stranded costs. The Commission further noted that the

States have a number of mechanisms available to them to

address stranded costs resulting from retail customers

who want to wheel in power from a different supplier.109

The Commission clarified the difference between its

jurisdiction over transmission in “interstate commerce”

and the States' jurisdiction over “local distribution.” It

upheld the view that the Commission had the jurisdiction

over the rates, terms, and conditions of unbundled

interstate transmission services by public utilities to retail

customers, including the authority to address retail

particular facilities in the case of vertically integrated

transmission and distribution utilities are transmission or

local distribution facilities. 

Implementation Procedures

The Commission proposed a two-stage implementation

process. In “Stage One,” the Commission would place

generic open access tariffs in effect simultaneously on a

certain date (60 days after the Final Rule) for every public

utility that owns and/or controls transmission facilities

and would establish rates for each public utility based on

the most current FERC Form 1 data. Both firm and non- 110

firm point-to-point transmission service and firm network

transmission service on a nondiscriminatory open access

basis will be included. In “Stage Two,” utilities will 111

have the option of proposing changes to the rates, terms,

and conditions in the generic tariffs 61 days after the Final

Rules go into effect. In addition, customers and others can

file complaints seeking changes. 

Concurrent with the issuance of the NOPR, the

Commission also issued a Notice of Technical Conference

and Request for Comments on establishing Real Time
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 57

In its final ruling, the Commission supported the concept of RINs in another format and renamed it the “Open Access Same-Time Information System 112

Rule” or OASIS.

The Commission subsequently issued its Notice of Proposed Rulemaking on Real-Time Information Networks and Standards of Conduct, Docket 113

No. RM95-9-000 (December 13, 1995). Under the proposal, each public utility (or its agent) that owns and/or controls facilities used for the transmission

of electric energy in interstate commerce would be required to create and/or participate in a RIN that would provide wholesale customers and potential

wholesale transmission customers with electronically provided information on available transmission capacity, prices, and other relevant information to obtain

open access nondiscriminatory transmission service.

The Commission provided an unprecedented level of detail in more than a thousand pages of documentation with respect to Order Nos. 888 and 889. 114

Federal Energy Regulatory Commission, Notice of Proposed Rulemaking: The Capacity Reservation Open Access Transmission Tariff, Docket No. 115

RM96-11-000 (April 24, 1996).

Federal Energy Regulatory Commission, Order No. 888, Final Rule issued on April 24, 1996 (Docket Nos. RM95-8-000, Promoting Wholesale 116

Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities, and RM94-7-001, Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities), p. 1.

Ibid., p. 11. 117

Annual estimated cost reductions or savings depend on, among other things, the assumptions regarding coal and natural gas prices. Refer to Federal 118

Energy Regulatory Commission, Final Environmental Impact Statement, FERC/EIS-0096 (Washington, DC, April 1996). 

The Commission expects that these additional savings (which have not been quantified) will be passed on to retail customers in retail rates which 119

would continue to be based on cost of service.

Information Networks (RINs). According to the Com- provide an orderly and fair transition to competitive bulk 112

mission, the establishment of RINs is expected to power markets without impairing the continued

ensure that potential purchasers of transmission services reliability of the industry. 

have access to information to obtain open access transmission services on a nondiscriminatory basis from the public

utilities. This goal will require each public utility to create

a RIN operating under industry-wide standards no later

than the date of issuance of the final rules on open access

transmission. In issuing the RIN notice, the Commission

sought comments on the type of information to be made

available and on the nature of standards to be incorporated. 113

The Final Rules: Order Nos. 888 and 889

On April 24, 1996, the Commission issued two separate

but interrelated final rules and a Notice of Proposed

Rulemaking pursuant to its authority under Sections 205

and 206 of the FPA. The first rule, Order No. 888, 114

addresses the twin issues of open access and stranded

costs. The second rule, Order 889, requires utilities to

establish electronic systems to share information about

available transmission capacity. This rule is known as the

Open Access Same-Time Information System (OASIS)

rule. In addition, the Commission issued a new Notice of

Proposed Rulemaking called the Capacity Reservation

Open Access Transmission Tariffs (CRT) NOPR. This

NOPR aims to establish a new system for the utilities to

use in reserving capacity on their own and others'

transmission systems.115

Taken together, the above provisions are expected to

“remove impediments to competition in wholesale trade

and to bring more efficient, lower cost power to the

Nation's electricity customers.” The Commission argues 116

that these rules will alleviate undue discrimination in

transmission services in interstate commerce and will

117

The type of discrimination addressed by the rules is,

namely, that a utility must provide service that is comparable to the service that it provides itself. Potential

quantitative benefits from these provisions are estimated

to be in the range of $3.8 billion to $5.4 billion per year of

cost savings. Nonquantitative benefits include better 118

utilization of existing assets and institutions, new market

mechanisms, technical innovations, and reduced rate

distortion.119

Open Access Final Rule

Elimination of monopoly power over transmission is the

primary objective of the above rules. To achieve this

objective, the Commission requires all public utilities that

own, control, or operate facilities used for transmitting

electric energy in interstate commerce to:

  File open access nondiscriminatory transmission

tariffs containing minimum terms and conditions 

  Take transmission service (including ancillary

services) for their own new wholesale sales and

purchases of electricity under open access tariffs

  Develop and maintain a same-time information

system that will give existing and potential users the

same access to transmission information that the

public utility enjoys

  Separate the transmission from generating and

marketing functions and communications.
58 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

All public utilities subject to the FPA's jurisdiction and their customers are affected by these rules, which go into effect 60 days after being published 120

in the Federal Register. Reciprocity is required for those receiving service under the new tariff.

Public Power Weekly (July 29, 1996). 121

Four categories of arrangements and accompanying agreements recognized in are: tight power pools, loose power pools, public utility holding company 122

arrangements and bilateral coordination arrangements.

Public Power Weekly (July 29, 1996). 123

The reciprocity provisions would be applicable to all customers, including municipally owned utilities and rural electric cooperatives that own, control, 124

or operate interstate transmission facilities. Apprehensions by nonpublic utilities that they may be denied transmission service (based on claims by public

utilities that their services are unsatisfactory) were taken into account by the Commission in developing a voluntary “safe harbor” procedure. This procedure

requires nonpublic utilities to submit their transmission tariffs to obtain the Commission's ruling with respect to their meeting the comparability criteria.

Nonpublic utilities that are members of a regional transmission group (RTG) can meet the comparability standard criteria through the RTG. 

Federal Energy Regulatory Commission, Notice of Proposed Rulemaking: Capacity Reservation Open Access Transmission Tariffs, Docket No. 125

RM96-11-000 (April 24, 1996). This NOPR requests comment on whether there are certain disadvantages inherent in offering transmission service on both

a network and point-to-point service. Underlying this request is the belief that a single-service open access tariff could possibly better accommodate

competitive changes in the industry and ensure fairness and nondiscrimination.

Various components of retail transmission costs are currently aggregated into a single, composite tariff. The generic term “unbundling” implies that 126

the individual cost components of retail transmission are disaggregated and shown separately. 

Based on the above directives, public utilities will file a

single open access tariff offering both network load-based

service and point-to-point contract-based service. The 120

final rule does not prescribe rates for network, point-topoint, or ancillary services. Instead, public utilities may

charge current rates or apply for new transmission rates.

The open access tariffs were due to be filed by July 9,

1996. As of that date, of the 166 utilities under the Com-  Corporate restructuring is not mandated, even

mission's jurisdiction, 165 had filed open access tariffs or though it is recognized that voluntary reorgawaivers. Of these 165 utilities, 144 filed tariffs, 21 filed nization may take place.

waiver requests, and 13 filed both tariffs and waiver requests seeking exemption from certain parts of the rule.  Since not all interstate transmission facilities fall 121

It should be noted that special provisions cover power

pools, public utility holding companies, and bilateral coordination arrangements. Because FERC's primary intent

is to eliminate undue discrimination in transmission access, a restructuring (or modification) of the existing tariff

structures is mandated. As an example, the term “coordination” applies to a variety of wholesale power sales

agreements within the industry that include interchange,

interconnection, pooling, and other agreements. These coordination arrangements and the agreements governing

them vary widely, ranging from simple bilateral arrangements to complex tight power pools. FERC determined 122

that certain wholesale agreements and arrangements must

be modified to ensure that necessary transmission services

for such arrangements and agreements are taken under

open access transmission tariffs and thus that such

arrangements and agreements are not unduly discriminatory. FERC allowed additional time until December 31,

1996, for transactions under these arrangements to comply

with the open access requirements. 123

Abrogation of existing requirement contracts is not

envisaged; however, the utilities or customers can seek  The Commission will permit utilities to seek

modification or termination of existing contracts on a case- recovery of stranded costs pertaining to wholesale

by-case basis. Modifications may also be necessary with

respect to coordination arrangements and contracts with

the intent of removing their discriminatory content.

Guidance regarding the voluntary formation of independent system operators is also provided.

Mention may also be made of some other relevant issues:

within the Commission's jurisdiction, reciprocity

provisions are included to preclude the possibility of

non-open access utilities taking unfair advantage of

open access utilities.124

  The Commission's review of market-based rates

would require that the seller (including its affiliates)

not have market power in generation and

transmission and not control barriers to entry.

  The Commission issued a new NOPR on capacity

reservation tariffs (CRTs) as an alternative means of

remedying discrimination.125

  The Commission reaffirmed its jurisdiction over the

rates, terms, and conditions of unbundled retail

transmission in interstate commerce by public

utilities. The Commission, however, did not wish 126

to encroach on the legitimate concerns of State

regulatory authorities in the area of restructuring or

in the way electricity is sold and regulated at the

retail level.
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 59

Federal Energy Regulatory Commission, Final Environmental Impact Statement, FERC/EIS-0096 (Washington, DC, April 1996). 127

Several other issues raised by the commenters with respect to the EIS were deemed to be outside its scope. These included State jurisdictional issues, 128

site-specific issues, and stranded cost issues. 

requirements contracts from departing customers by

direct assignment. Utilities may seek recovery of

stranded costs caused by retail wheeling through the

Commission only in cases where the State regulatory

authority does not have authority under State law to

address stranded costs when retail wheeling is

required.

Environmental Considerations

Open transmission access may open opportunities for

purchases of power from some power plants that would

emit more nitrogen oxides (NO ) than would the sources x

they would displace. Since NO emissions are related to x

ground-level ozone formation with its associated adverse

health and environmental effects, the Commission analyzed the possible environmental impacts of its Final Rule

with specific reference to an increase in NO emissions. x

127

In its Final Environmental Impact Statement (FEIS), FERC

maintained that requiring the utilities to open their

electricity transmission facilities would have only minimal

impacts on the environment during the next 15 years.

Overall, the FEIS provides the following results:

  The relative prices of natural gas and coal have a

larger impact on NO emissions than any impacts x

from the proposed rule

  The proposed rule is projected to have only slight

impacts on NO emissions, and the impacts are as x

likely to be beneficial as to be harmful

  Even a substantial increase in transmission capacity

would change emissions estimates by very small

amounts 

  In the worst-case scenario, emission impacts are

negligible or nonexistent, with increases in the range

of 2 to 3 percent by the year 2005

  Mitigation of NO emissions and ozone formation x

should be addressed comprehensively (within the

existing legal framework) rather than on a piecemeal

basis by the Commission.

The above conclusions prompted the Commission not to

initiate any interim mitigation measures that might

undermine the basic goals of its open access rule.

Acknowledging its inability to initiate and administer a

national environmental program, the Commission

nevertheless expressed its intent to assist development of

long-term programs designed to reduce NO emissions in x

close collaboration with the Environmental Protection

Agency (EPA) and the Ozone Transport Assessment

Group (OTAG). A summary of the major provisions of 128

Order 888 is provided in the following insets.

Major Provisions of FERC Order 888 on Stranded Costs

Stranded Cost Requirement Stranded Cost Recovery for Retail-Turned-Wholesale Customers

The recovery of legitimate and verifiable stranded costs shall be allowed.

Direct assignment of stranded costs computed on a revenues lost basis

is the appropriate method for recovery

FERC shall be the primary forum for addressing recovery of stranded

costs caused by retail-turned-wholesale customers. A utility may seek

recovery of stranded costs associated with a retail customer who

becomes a legitimate wholesale transmission customer as a result of

access to wholesale transmission through rates for wholesale

transmission services to that customer. An evidentiary demonstration

must be made. Any recovery permitted by a State will be deducted from

the FERC-determined stranded cost recovery.

 Wholesale Stranded Cost Definition

Any legitimate, prudent, and verifiable cost incurred by a utility to provide

service to a wholesale requirements customer, a retail customer, or a

newly created wholesale power sales customer that subsequently

becomes, in whole or in part, an unbundled wholesale transmission

services customer of such utility.
60 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

Major Provisions of FERC Order 888 on Stranded Costs (Continued)

Contract Definitions Recovery of Retail Stranded Costs

A new contract is one executed after July 11, 1994, or extended or Although both FERC and States have the legal authority to address retail

renegotiated to be effective after July 11, 1994. stranded costs, FERC determined that States should have primary

An existing contract is one executed on or before July 11, 1994. wheeling. A utility may seek recovery of stranded costs through

jurisdiction over the recovery of stranded costs arising from retail

transmission rates from customers who obtain retail wheeling only if the

State regulator has no authority under State law to address stranded

costs at the time retail wheeling is required. A similar evidentiary

demonstration must be made.

Stranded Cost Recover Under New Contracts Evidentiary Demonstration

A public utility may not seek recovery of stranded costs under new A utility seeking recovery of stranded costs must demonstrate that it

contracts except in accordance with an exit fee or other explicit provision incurred the costs on behalf of the wholesale requirements customer

contained in the contract. Prior notice to FERC of termination of new or retail customer based on a reasonable expectation that the utility

power sales contracts is no longer required. would continue to serve the customer.

A public utility may not seek recovery of stranded costs under new

contracts except in accordance with an exit fee or other explicit provision

contained in the contract. Prior notice to FERC of termination of new

power sales contracts is no longer required.

Stranded Cost Recovery Under Existing Contracts

A public utility may seek recovery of stranded costs under existing

contracts that do not contain exit fees or other explicit stranded cost

provisions as follows:

3 The parties may negotiate a stranded cost amendment and file

it with FERC.

3 Either party may seek FERC approval of a stranded cost

amendment under Section 205 or 206 any time prior to the

expiration of the contract .

3 The public utility or transmitting utility may file a proposal to recover stranded costs through Section 205 or Section 211-212

rates for wholesale transmission services to the customer. 

FERC will reject stranded cost amendments to existing contracts that

include explicit provisions for payment of stranded costs or exit fees.

If the existing contract contains a notice provision, there will be a

rebuttable presumption that the utility had no reasonable expectation of

continuing to serve the customer beyond the term of the notice

provision.

Whether State law awards exclusive service territories and imposes a

mandatory obligation to serve would be among the factors to be

considered in determining whether the reasonable expectation test is

met in a particular case involving either a retail or retail-turnedwholesale customer.

Determination of Recoverable Wholesale Stranded Costs

Determination of recoverable stranded costs shall be based on a

"revenues lost" approach. The utility shall calculate a customer's

stranded cost liability using the following formula:

SCO = (RSE - CMVE) x L where

SCO = Present value of stranded cost obligation

RSE = Average annual revenues from the departing generation customer

over the 3 years prior to the customer’s departure (with the variable cost

component of revenues clearly identified), less the average transmissionrelated revenues that the host utility would have recovered from the

departing generation customer over the same 3 years under its new

wholesale transmission tariff.

Advanced Notice of Stranded Cost Calculation

Prior to the termination date of an existing contract, a customer may

request the utility to calculate the customer's stranded costs exposure

using the prescribed formula. The utility would have 30 days or a

mutually agreed upon period to respond. If the customer believes that

the utility has failed to establish reasonable expectation, the customer

has 30 days to respond so to the utility. If the parties cannot reach a

mutually agreeable charge within a reasonable time period, the

customer can file a complaint with FERC or contest the charge when the

utility files it.

 Source: Adapted from “FERC Finalizes Electric Industry Restructuring Rule,” Public Utility Topics, No. 96-2 (Philadelphia, PA: Coopers &

Lybrand, L.L.P.), p. 5.
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 61

Major Provisions of FERC Order 888 on Open Access

Functional Unbundling Reciprocity

A utility's uses of its own transmission system for the purpose of Transmission customers of jurisdictional utilities who take service under

engaging in wholesale sales and purchases must be separated from the open access tariff and who own, control, or operate transmission

other activities. Corporate unbundling is not required. facilities must, in turn, provide open access service to the transmitting

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.

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, loadbased 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 Pricing

Jurisdictional utilities who are members of tight or loose power pools The rule does not prescribe rates for network, point-to-point, or ancillary

must file either an individual pro forma tariff or a joint pool-wide pro forma services. Instead, utilities may charge current rates or apply for new

tariff by July 9, 1996. They are not required to take service for pool transmission rates. Utilities can propose to recover opportunity costs

transactions under that tariff, but are required to file a joint pool-wide and expansion costs. Crediting for customers' transmission facilities will

tariff no later than December 31, 1996, and begin to take service under be permitted on a case-by-case basis. Proposed pricing must conform

that tariff for all pool transactions by that same date. By that date, they with FERC's Transmission Pricing Policy Statement.

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.

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 Market-Based Rates

Any entity engaged in wholesale purchases or sales of energy or retail Utilities seeking market-based rates for sale of electricity at wholesale

purchases is an eligible customer. 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, No. 96-2 (Philadelphia, PA: Coopers &

Lybrand, L.L.P.), p. 4.
62 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

This rule was issued in tandem with the Commission's Open Access Final Rule (Order 888). Refer to Federal Energy Regulatory Commission, Open 129

Access Same-Time Information System (formerly Real-Time Information Networks) and Standards of Conduct, Docket No. RM95-9-000 (April 24, 1996).

The Commission relied on the efforts of two industry-led groups in formulating the rule on some of the issues. The first group (called the What 130

Group) led by the North American Reliability Council (NERC) assisted in the preparation of a report on what information should be included in the RIN.

The second group (called the How Group) led by the Electric Power Research Institute (EPRI) facilitated the formulation of how to implement the suggestions

of the What Group. 

The basic OASIS required by this rule is expected to be in place and operational by November 1, 1996. Its development will continue in the next 131

phase for development of a fully functional OASIS.

Principles of FERC Order 888 for Independent System Operators (ISOs)

1. The ISO's governance should be structured in a fair and nondiscriminatory manner.

2. An ISO and its employees should have no financial interest in the economic performance of any power market

participant. An ISO should adopt and enforce strict conflict-of-interest standards.

3. An ISO should provide open access to the transmission system and all services under its control at non-pancaked

rates pursuant to a single, unbundled, grid-wide tariff that applies to all eligible users.

4. An ISO should have the primary responsibility in ensuring short-term reliability of grid operations. Its role should be

well defined and comply with applicable standards set by the North American Electric Reliability Council and the

regional reliability council.

5. An ISO should have control over the operation of interconnected transmission facilities within its region.

6. An ISO should identify constraints on the system and be able to take operational actions to relieve those constraints

within the trading rules established by the governing body. These rules should promote efficient trading.

7. An ISO should have appropriate incentives for efficient management and administration and should procure the

services needed for such management and administration in an open competitive market.

8. An ISO's transmission and ancillary services pricing policies should promote the efficient use of, and investment in,

generation, transmission, and consumption. An ISO or an RTG of which an ISO is a member should conduct such

studies as may be necessary to identify operational problems or appropriate expansions.

9. An ISO should make transmission system information publicly available on a timely basis via OASIS.

10. An ISO should develop mechanisms to coordinate with neighboring control areas.

11. An ISO should establish an Alternative Dispute Resolution (ADR) process to resolve disputes in the first instance.

 Source: Adapted from “FERC Finalizes Electric Industry Restructuring Rule,” Public Utility Topics, No. 96-2 (Philadelphia,

PA: Coopers & Lybrand, L.L.P.), p. 9.

Information Systems, Standards of

Conduct, and Independent System

Operators (ISOs)

The second rule, Order No. 889, also known as the Open

Access Same-Time Information System (OASIS) rule

(formerly called Real-Time Information Networks or

RINs) requires utilities to share information available on

the electronic system and prescribes the Standards of

Conduct. This rule was issued after a review of the 129

comments filed with the Commission in response to its

notice of proposed rulemaking (also known as the RIN

NOPR) on December 13, 1995. 130

Under this rule, each public utility (or its agent) that owns,

controls, or operates transmission facilities will create or

participate in an OASIS that will provide open access

transmission customers (current and potential) with

electronic information about transmission capacity, prices,

and other information necessary to obtain open access

nondiscriminatory transmission service. Accordingly, the

rule will require the public utilities to obtain information

about the transmission system for their own wholesale

power transactions in the same way as their competitors

do via the OASIS. The rule is thus expected to ensure that

transmission owners (and their affiliates) do not have an

unfair advantage in transmission usage to sell power.131
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 63

Compliance with this rule should have been achieved by November 1, 1996. The FERC, however, granted the industry’s request for an extension 132

of the starting date for the OASIS. It will now start on January 3, 1997.

An ISO is an operator of a designated set of transmission facilities. The discussion of the ISOs is part of a wider discussion that includes such related 133

subjects as coordination arrangements, power pools, tight power pools, loose power pools, public utility holding companies, and bilateral coordination

arrangements.

See Federal Energy Regulatory Commission, Notice of Proposed Rulemaking: Capacity Reservation Open Access Transmission Tariffs, Docket 134

No. RM96-11-000 (April 24, 1996). 

The NOPR stipulates that each utility subject to the open access rule file a CRT no later than December 31, 1997. 135

The rule also establishes standards of conduct to ensure The above provisions of the Open Access Final Rule tariff

that a public utility's employees engaged in transmission are designed to remedy discrimination in interstate transsystem operations function independently of those mission service. Some stakeholders, however, expressed

employees engaged in wholesale purchases and sales of the view that the operation of the Final Rule in concert

electric energy in interstate commerce. Specifics with with the provisions of the OASIS renders the system too 132

respect to various standards and protocols to ensure that inflexible to accommodate industry innovations. It may

the OASIS system presents information in a consistent and also be necessary to place all transmission customers on

uniform manner (subject to the accommodation of an equal footing.

additional changes as may become necessary in the

future) have also been detailed.

The Commission noted that many utilities plan to go

beyond the concept of functional unbundling (requiring

the separation of generation and transmission) and turn

over transmission to an independent system operator

(ISO). While not mandating the formation of ISOs, the 133

Commission encouraged their creation. 

Recognizing that the ISOs will fall under the Commission's jurisdiction, specific guidelines for their creation

have been stipulated. Of these, the most critical is the

requirement that the management and control of ISOs be

completely independent of generation owners so as to

ensure compliance with the Commission's nondiscriminatory transmission tariff requirements. Other guidelines

deal with responsibilities of ISOs that include management, pricing issues, and related matters.

The Capacity Reservation Open Access

Transmission Tariff NOPR

The Open Access Final Rule requires each public utility

that owns, operates, or controls facilities used for the

transmission of electric energy in interstate commerce to

file an open access nondiscriminatory tariff and to take

transmission service for their own wholesale sales and

purchases under this tariff. The Final Rule makes two

different types of transmission service available in one

tariff: (1) network service, which is based on use (i.e.,

load), and (2) point-to-point service, which is based on

transmission capacity reservations. Fixed costs of transmission systems are allocated among network customers

on the basis of use (i.e., loads) and among point-to-point

customers on the basis of their reservations (i.e., contract

demands). 

In view of the foregoing, FERC issued a Notice of

Proposed Rulemaking (NOPR) in conjunction with the

issuance of the Open Access Final Rule. This NOPR, 134

known as the “Capacity Reservation Open Access Tariff,”

proposes to replace the Open Access Final Rule tariff with

a single service open access capacity reservation tariff that

would accommodate both network and point-to-point

needs. Transmission products and services should be 135

provided on an open access, comparable basis. With a

view to ensure comparability, transmission service should

be nominated and reserved on a nondiscriminatory basis.

The basic service concept in the CRT is that all firm

transmission service be reserved and that all reserved

service be firm service. Reservations of capacity thus

permit the customer to receive up to a specific amount of

power on the grid at specific “points of receipt” and to

deliver up to a specific amount of power from the grid at

specified “points of delivery.” A customer with a capacity

reservation would be entitled to use the reservation either

to deliver the power or receive it. 

FERC maintains that adoption of this procedure will

provide a better alternative to accommodate competitive

changes occurring in the industry. Other arguments in

support of CRT include:

 Under a CRT approach, the capacity requirements of

each customer, including those of the provider, would

be clearly known, permitting all customers to be treated

comparably. In order to ensure comparability, transactions could thus become transparent

 The CRT allows all jurisdictional customers to be

placed on the same footing, in that all customers not

only reserve capacity but pay for the capacity reserved.
64 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

The contract path method, it is contended, does not correspond to the physical flows on the network, implying that the market view and uses of the 136

network may be inconsistent with the physical view of the system needed for reliability.

The NOPR lists a number of potential changes in the power industry, including independent system operators, regional transmission groups, regional 137

power exchanges, generation divestiture, distribution company spinoffs, unified regional transmission ownership, regional transmission tariffs, megawatt-mile

transmission pricing, and congestion transmission pricing.

See S.M. Harvey, W.W. Hogan, and S.L. Pope, “Transmission Capacity Reservations Implemented Through a Spot Market with Transmission 138

Congestion Contracts,” Electricity Journal (November 1996), pp. 42-55.

Comments of the North American Electric Reliability Council submitted to the Federal Energy Regulatory Commission in the matter of Notice of 139

Proposed Rulemaking and Request for Comments on Capacity Reservation Open Access Transmission Tariffs, Docket No. RM96-11-000 (October 21,

1996).

Electric Utility Weekly (April 29, 1996). 140

Order 888 lists some of the differences between investor-owned and publicly owned utilities. Some of these arise from the use of tax-exempt 141

financing, restrictions on rate-setting methods, and statutory restrictions on services that publicly owned utilities can provide. Rural cooperatives also differ

significantly from investor-owned utilities.

The Nebraska Public Power District filed application for a rehearing on this subject with the Commission on May 24, 1996. 142

Refer to Energy Report (June 3, 1996). 143

 The CRT permits a basis for a regional flow-based outlined in the March 29, 1995, Mega-NOPR.

pricing mechanism considered superior to the contract- However, the Commission's provisions on many

path pricing in the Final Rule. issues have not been universally acceptable to all. 136

 The CRT approach may facilitate transmission plan- follows:

ning for all users.

 Since load-based network service will be difficult to

sell, the need to monitor the secondary market as a risk

management tool will be greatly minimized. Growth 137

of secondary market transactions is accordingly contained.

FERC's CRT proposals are deemed to be conceptually

compatible with a competitive bulk power market.138

However, there are many details that need to be spelled

out. The North American Electric Reliability Council

(NERC) recently stated that the CRT NOPR, as it is currently written, lacks sufficient details and more discussion

is needed to develop a well-defined model that would

make sense commercially and economically. To meet 139

this objective, NERC stated that technical principles that

are unique to the operation of interconnected electric networks should be addressed in tandem with commercial

market needs to define a transmission service model that

will be commercially workable and operationally

practical. 

The Post-888 Reactions 

Observers point out that there were few surprises in the

Commission's landmark ruling designed to propel the

industry toward a more competitive, nondiscriminatory

open access wholesale market. The final rules on open

access, stranded cost recovery, and electronic transmission

information networks remain within the framework

140

Some of the issues that are causing controversy are as

  FERC’s action to permit full recovery of stranded

costs from departing wholesale customers is perhaps

the most contentious issue. Support as well as

opposition to this move comes from multiple sources.

Customers who cannot get lower electricity prices

immediately consider FERC’s action as delaying the

benefits of competition. Those whose assets are in

jeopardy consider that the move enables them to

remain in business and become competitive.

  Many municipals, cooperatives, and foreign utilities

find the reciprocity provision for public utilities

intrusive and unacceptable. The Nebraska Public 141

Power District (NPPD) told the Commission that the

State had no investor-owned utilities and viewed the

reciprocity requirement as unconstitutional. Appli- 142

cation of the reciprocity requirement, as envisaged in

Order 888, infringes on State sovereignty. According

to NPPD, there is no compelling reason to require

reciprocity, and voluntary participation will

eventually emerge without FERC's imposition.143

  State regulatory authorities disagree with the

extension of FERC's jurisdiction over unbundled

transmission services provided to retail trade

customers and the recovery of stranded costs when

retail trade customers become wholesale customers.

According to the National Association of Regulatory

Utility Commissioners (NARUC), FERC’s assertion

of authority over the rates, terms, and conditions
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 65

Refer to testimony by the National Association of Regulatory Utility Commissioners before the U.S. Senate Committee on Energy and Natural 144

Resources on Competitive Changes in the Electric Power Industry: Orders 888 and 889 of the Federal Energy Regulatory Commission (Washington, DC,

July 11, 1996). 

Gas Daily (May 14, 1996). 145

OTAG is the 37-State group formed to find a regional solution to the pollution transport problem. 146

Federal Energy Regulatory Commission, Notice of Inquiry: Inquiry Concerning Commission's Merger Policy Under the Federal Power Act, Docket 147

No. RM96-6-000 (Washington, DC, January 31, 1996).

Because of the November 9, 1965, blackout affecting the northeastern United States, the electric utility industry was given an opportunity to either 148

improve the operations of the electrical systems and promote reliability or face mandatory obligations from regulatory and legal actions. The electric utility

industry formed a voluntary organization that handled self-regulation through peer reviews. That organization has evolved into the North American Electric

Reliability Council (NERC). NERC consists of nine Regional Reliability Councils and one Affiliate whose members account for virtually all the electricity

supplied in the United States, Canada, and a portion of Baja California Norte, Mexico. The members of these Councils are from all segments of the electricity

supply industry—investor-owned, Federal, rural electric cooperative, State/municipal, and provincial utilities, independent power producers, and power

marketers.

For an excellent discussion of the reliability concepts, refer to North American Electric Reliability Council, Reliability Concepts (Princeton, NJ, 149

February 1985).

A more specific definition of reliability, “in a bulk power system, is the degree to which the performance of the elements of that system results in 150

power being delivered to consumers within accepted standards and in the amount desired. The degree of reliability may be measured by the frequency,

duration, and magnitude of adverse effects on consumer service.” The two basic functional aspects of the bulk power system are adequacy and security.

Adequacy is the ability of the bulk power electric system to supply the aggregate electric power and energy requirements of the consumers at all times, taking

into account scheduled and unscheduled outages of system components. Security is the ability of the bulk power system to withstand sudden disturbances

such as electric short circuits or an unanticipated loss of system components.” North American Electric Reliability Council, Reliability Concepts (Princeton,

NJ, February 1985).

Bulk power electric system is a term describing the aggregate of electric generating plants, transmission lines, and appurtenant equipment. The term 151

may refer to those facilities within one electric utility, or within a group of utilities in which the transmission lines are interconnected. North American Electric

Reliability Council, Reliability Concepts (Princeton, NJ, February 1985).

of unbundled retail transmission services is based on in a way that results in the restriction of output, the

a flawed understanding of the roles established for resulting prices may no longer be competitive in

State and Federal regulators. wholesale or retail markets. 144

  Environmentalists and lawmakers in the Northeast

raised the possibility that increased emissions from

coal-fired plants in the Midwest may result in a

deterioration of the environment, particularly in the

Northeast, and petitioned the U.S. Environmental

Protection Agency (EPA) to refer the matter to the

White House Council on Environmental Quality

(CEQ) for review. On May 13, 1996, the EPA did 145

refer the matter to the CEQ but did not ask that

implementation of Order 888 be stayed. EPA also

expressed its intent to work with the Ozone Transport

Assessment Group (OTAG) to devise a regional capand-trade program for NO emissions from power x

plants. In the meantime, FERC initiated a Notice of 146

Inquiry to solicit comments on the air pollution

impacts of Order 888. The Department of Energy has

also been directed by the White House to monitor

emission levels in the future.

  There is apprehension that the attempt to usher in

competition and lower prices may be impeded if the

process results in the creation of “mega-mergers”

with market power incompatible with competitive

norms. For example, if one or a group of suppliers

acquires the capability (by increasing market power)

  FERC has initiated a reevaluation of its merger policy

with a Notice of Inquiry (NOI) on whether its criteria

and policies for evaluating electric utility mergers

need to be revised in view of the changes confronting

the industry.147

Reliability Issues

Reliability in the United States is covered by government

and industry. The interstate trade sections of the Federal

Power Act assigned the oversight responsibility first to the

Federal Power Commission (since known as the FERC)

and later to the Department of Energy. Industry participation is handled by NERC. To lay the groundwork 148

for a general discussion of the issues concerning reliability, a workable definition of the term is necessary. In 149

its naive version, reliability implies that power will be

available when it is needed. Stated another way, the term

reliability connotes how well your utility succeeds in

giving you (or the customers) the quality or the continuity

of service desired. Most discussion concerning 150

reliability concepts, however, revolves around the bulk

power electric system and the degree to which its

performance affects the continuity of power supply to the

customers.151
66 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

The “rules of the road” refer to a set of policies, standards, criteria, principles, and guides established by NERC for electric interconnection operation 152

and planning. NERC remains confident about the future even though it is conceded that different mechanisms may be needed to ensure the necessary

operational discipline needed for reliability. Refer to North American Electric Reliability Council, 1995 Annual Report (Princeton, NJ, 1996).

Based on a report in Electric Utility Week (August 18, 1996). 153

P. Haase, “Breakthrough in Stability Analysis,” EPRI Journal (July/August 1996), pp. 25-30. 154

U.S. Department of Energy, The Electric Power Outages in the Western United States, July 2-3, 1996 (Washington, DC, August 1996). 155

It is generally presumed that the deregulation of the future provided [emphasis added] it can adapt the current

industry and the introduction of open access would not structure to the new competitive environment facing the

impact the requirement to maintain reliable electric industry.” For this purpose, DOE will recommend

systems. However, with challenges confronting the utili- changes and process improvements to address reliability

ties in a competitive environment, there is uncertainty as challenges as the restructuring process unfolds. DOE will

to whether compliance with the venerable “rules of the also create a task force to define a research agenda to

road” for electric interconnection and planning will be address issues pertaining to ensuring reliability. 

maintained as it has been in the past.152

Potential changes in market behavior contribute to

reliability concerns. Take, for example, the price differential between the Northwest and Southwest, which is

capable of triggering huge shifts in energy that cannot be

supported by the existing transmission system. It is

pointed out that in the past utilities operated transmission

and generation capacity according to preventive operating

procedures to guard against system disturbances,

including running sufficient generating capacity to

provide operating reserves in excess of demand and

limiting power transfers on the system to be able to

handle a single contingency. Today, much of that excess

is being sold on the market. As a result, the system is

taxed to the maximum in an effort to make profits. Unless

the new entrants can also envision the culture of

reliability, problems are likely to occur.153

A somewhat similar view has been expressed by the

Electric Power Research Institute (EPRI). EPRI states that

as utilities increase maximum utilization of their

transmission and distribution assets, efficiency may be

enhanced but stress on power grids increases. As higher

loads and more power transfers take place, electric

systems are being operated nearer and nearer their

physical limits. Serious new stability problems are

cropping up, problems that have long-distance impacts

not predicted by conventional stability analysis tools. In

this context, the division of vertically integrated utilities

reduces the ability of any one organization to manage

global power flow.154

As a result of the western electric power outage of July 2,

1996, the Department of Energy (DOE) provided a report Competition

to the President with respect to the causes, responses, and

preventability of the incident. While conceding that the

present institutional framework (to promote reliability)

remains essentially sound, “it will continue to work in the

155

Industry changes will thus cause modifications to be made

which would ensure system reliability. Within this

changing environment, it is not known who will be

responsible for future planning and construction for the

electrical transmission system (additions and upgrades),

either as a unified approach or through an operational

entity. No group in the electric power industry has

stepped forward to take responsibility for building new

lines and supplying equipment to support out-of-State

electrical system usage. Unbundled electric utilities will

not consider projects outside their service territories or

competitive markets. However, how system reliability

will function in a period of downsizing and cost cutting

remains to be seen.

Conclusions

Events in the electric utility industry are moving faster

than anticipated. The issuance of Orders 888 and 889 sets

in motion a chain of events that will take time to unfold

and establish. While the intent to deregulate generation

has been established and barriers to competition have

been lowered, some stakeholders uphold the view that the

transition to a full-fledged competitive trade in electricity

will be a slow process. Maintaining system reliability may

perhaps be the most critical determinant in the spread of

competition. The spirit of prevailing cooperation on this

and other related issues will benefit the industry in a

rapidly changing atmosphere.

Role of States in Promoting

Title VII of EPACT included amendments to the FPA and

PUHCA that were designed to encourage increased

reliance on competition and market mechanisms in the
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 67

See Appendix F. 156

National Regulatory Research Institute, A White Paper on the Energy Policy Act of 1992: An Overview for State Commissions of New PURPA 157

Statutory Standards (Columbus, OH, April 1993).

Title VII of EPACT enabled FERC to direct an electric utility to provide “wholesale wheeling.” No such provisions were made with respect to retail 158

wheeling. 

Information contained in this section draws on the research undertaken by Dr. Jeff Fang of the National Renewable Energy Laboratory with funding 159

provided by the Energy Information Administration.

California Public Utility Commission, Decision 92-09-088, W4, 32, “Order Instituting Investigation on the Commission's Own Motion To Implement 160

the Biennial Resource Plan Update Following the California Energy Commission's Seventh Electricity Report,” (September 16, 1992).

Refer to California Public Utility Commission, California's Electric Services Industry: Perspectives on the Past, Strategies for the Future (San 161

Francisco, CA, February 1993). 

California Public Utility Commission, “Order Instituting Rulemaking on the Commission's Proposed Policies Governing Restructuring California's 162

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).

electric utility industry. Many of the provisions affected Based on a comprehensive reexamination of the electric 156

State utility commissions and their regulated utilities. utility industry in the State and the regulatory policy 157

Faced with the most sweeping legislation affecting the under which the industry functioned, the CPUC opened

industry, the State utility commissions commenced rulemaking and investigative proceedings to consider its

evaluating the adequacy and compatibility of their proposed restructuring policies in early 1994. These

regulatory framework to meet the challenges likely to initiatives, popularly known as the “Blue Book” proconfront the industry in the future. posals, outlined a strategy to replace the traditional costIn the years following enactment of EPACT, there has

been a surge of activity at State 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. 158

Regulatory Initiatives159

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, had compelling reasons to promote competition in

the hope of making lower rates available to their consumers in general. 

As an example, the California Public Utility Commission

(CPUC) directed an examination of the comprehensive set

of regulatory programs in order to explore alternatives to

the current regulatory approach based on conditions and

trends identified in its Decision No. 92-09-088 of September 1992. This directive resulted in the submission 160

of a staff report—generally known as the “Yellow

Book”—to the CPUC in February 1993. 161

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.

162

of-service regulatory framework with alternatives that

focused on utility performance and, where possible, the

discipline of the market.

Other States that commenced early consideration of the

issues include New York, Michigan, Massachusetts, and

Wisconsin. Since then, most other States have also begun

addressing issues associated with promoting industry

competition. As of June 30, 1996, 44 States and the District

of Columbia (more than 88 percent of the Nation's

regulatory commissions) had started restructuring

activities in one form or another. Commissions may

undertake a range of activities resulting in concrete plans

for implementation, or their activities may be purely

exploratory with potential for developing plans for retail

wheeling in the future. For some commissions, the

process may be purely informational, with action, if any,

to be taken at some future date.

Among the 45 jurisdictions that have initiated restructuring activities, 24 have formal proceedings in progress,

18 are conducting informal inquiry or study, and only 3

States have made “final” decisions concerning the scope

of competition and the type of market structure to go with

it in the future.

State utility commissions that have initiated formal

proceedings (as of June 30, 1996) are Arizona, Connecticut, Delaware, District of Columbia, Idaho, Iowa,

Louisiana, Maine, Massachusetts, Michigan, Minnesota,

Montana, Nevada, New Hampshire, New Jersey, New

Mexico, Ohio, Oklahoma, Pennsylvania, Texas, Utah,

Vermont, Virginia, and Washington.
68 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

The Michigan Public Service Commission (MPSC) specified that the program will be started when the utilities plan to solicit new capacity. Neither 163

Detroit Edison Company nor Consumers Power Company has requirements for capacity in the near term. To complicate matters, the two utilities challenged

the authority of the MPSC to order retail wheeling. As a result, the MPSC has opened a proceeding to address the recommendations of the Michigan Jobs

Commission concerning restructuring. Subsequent regulatory action in Michigan was initiated at the specific request of the State's executive branch. Governor

John Engler of Michigan released (in January 1996), a “blueprint” for electric and gas utility reform based in part on reports submitted by the Michigan Jobs

Commission. The MPSC has not yet concluded its study based on the recommended “blueprint.”

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 164

in the Electric Industry” (August 16, 1996).

Note that Nebraska has no privately owned electric utilities. All generation, transmission, and distribution service in Nebraska is provided by public 165

entities, municipalities, and cooperatives whose governing boards are responsible to, and serve at the voting pleasure of, rate-paying Nebraska citizens.

On July 3, 1995, Legislative Resolve Resolve to Require a Study of Retail Competition in the Electric Industry became Maine Law. This legislation 166

directed the Maine Public Utilities Commission (MPUC) to begin a study and submit its findings to the Legislature by January 1, 1997. The study must

develop at least two plans for an orderly transition to a competitive market and must identify the plan the MPUC believes to be in Maine's best interests. The

MPUC, in response to this legislation, issued its draft report on July 19, 1996.

The New Hampshire legislature, for example, passed legislation in June 1995 directing the New Hampshire Public Utility Commission (NHPUC) 167

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,

directs 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.

As of June 30, 1996, there was no legislative activity in Alaska, Arkansas, Colorado, Florida, Georgia, Hawaii, Idaho, Indiana, Kentucky, Louisiana, 168

Maryland, Michigan, Missouri, Montana, North Carolina, North Dakota, South Carolina, South Dakota, Tennessee, Utah, Vermont, Washington, West

Virginia, Wisconsin, Wyoming, or the District of Columbia.

Other State commissions that have initiated informal

inquiry or study (as of June 30, 1996) include Alaska,

Colorado, Georgia, Hawaii, Illinois, Indiana, Kansas, Kentucky, Maryland, Mississippi, Missouri, North Carolina,

North Dakota, Oregon, Rhode Island, South Carolina,

West Virginia, and Wyoming. State commissions in California, New York, and Wisconsin had taken final

decisions by the end of June 1996.

Five States (Illinois, Massachusetts, Michigan, New

Hampshire, and New York) have already instituted retail

wheeling experiments or pilot programs. However,

Michigan's program has been overtaken by events. The 163

experiences of these States will be closely watched by

those interested in initiating similar activities.

Only a small minority of 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, notes 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 up, and, at the same time, deregulation

could result in the diminution of the quality of service

enjoyed by the ratepayers in the State. The Nebraska 164

Public Power District (NPPD) maintains that applying

reciprocity requirement provisions of FERC Order 888

violates Nebraska's law and its constitutional rights.165

Finally, no regulatory activity had been reported in six

States: Alabama, Arkansas, Florida, Nebraska, South

Dakota, and Tennessee (as of June 30, 1996).

Legislative Activities

All State utility commissions typically enjoy broad

regulatory authority to ensure that electric utilities in their

jurisdiction 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 may be designed primarily to

grant the utility regulatory agency the authority to

address the restructuring issues or to consider alternative

ratemaking processes (incentive- or performance-based

regulation). Elsewhere, State legislators may evince a

serious interest in finding out how the State should

respond to new competitive pressures emerging in the

electric industry. Exploratory activities may also be 166

promoted at the behest of the State legislators in an effort

to gain additional insights. In some cases, legislative 167

actions may become necessary to adopt decisions

recommended by the commission(s) for implementation.

As of June 30, 1996, 25 States were addressing restructuring-related activities, while the other 25 States and the

District of Columbia had no such activity. Of the 25 168

States with legislative activities, 12 have enacted some legislation: Alabama, Arizona, Connecticut, Delaware, Kansas, Maine, Mississippi, New Hampshire, New Jersey,

Oregon, Texas, and Virginia. Legislation is under consideration in 6 States: California, Massachusetts, New York,
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 69

The California legislature enacted a landmark electric deregulation bill (AB 1890) on August 31 and September 1, 1996. The bill was signed into 169

law by Governor Pete Wilson on September 23, 1996.

Ohio, Pennsylvania, and Rhode Island. The 7 States-  Other remaining issues, including environmental 169

undertaking studies are Illinois, Iowa, Minnesota, considerations and support for public policy

Nebraska, Nevada, New Mexico, and Oklahoma. Table 5 programs (such as demand-side management,

shows the status of electric industry restructuring, by assistance to low income households, support for

State, as of June 30, 1996. green power, and others)

Issues Under Consideration

A wide range of issues are under consideration by the

States. Critical among them are the following:

  Industry structure, including functional unbundling

and/or divestiture of generation assets

  Creation of independent system operators and power

exchanges

  Estimation and recovery of strandable costs 

  Evaluation of the current “obligation to serve”

requirement in a deregulated environment

  Timetable for implementation.

The above issues are complex and do not easily lend

themselves to solutions that are acceptable to all stakeholders. Most State proceedings are, therefore, involved

in an ongoing dialogue with all stakeholders to reach a

possible consensus on issues involved. Even where

decisions have been made, it is open to parties to take up

the matter at a judicial level. It is, therefore, likely that

deregulation of the electric utility industry will take time

to be completed and to be effective.
70 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update Table 5. Status of Electric Industry Restructuring by State, as of June 30, 1996 State Competition Institutions Assets Investment Charge Energy Ratemakin

Regulatory Legislative Overall Status Type of New Generation Stranded Benefits Renewable Based Transition Costs/ System Performanc

Alabama No activity Bill enacted Authority 

to consider granted 

Alaska Informal inquiry No activity Arizona Formal proceed- Bill enacted 

ing in progress 

Arkansas No activity No activity California Final decision, Under consid- Wholesale and ISO, Power Functional Recovery Yes (r) Renewables Yes (r) 12/20/95 eration retail (r) Exchange (r) unbundling, allowed (r) portfolio Incentives for standard (r) voluntary divestiture (r) Colorado Informal inquiry No activity Connecticut Formal proceed- Bill enacted Authority 

ing in progress granted by 

HB 5045, 5/2/96 

Delaware Formal proceed- Bill enacted Wholesale Recovery 

ing in progress and retail (r) allowed (r) 
Table 5. Status of Electric Industry Restructuring by State, as of June 30, 1996 (Continued)

State Competition Institutions Assets Investment Charge Energy Ratemakin

Regulatory Legislative

Overall Status

Type of New Generation Stranded Benefits Renewable Based

Transition

Costs/ System Performanc

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 71 District of Formal proceed- No activity 

Columbia ing in progress Florida No activity No activity Georgia Informal inquiry No activity Hawaii Informal inquiry No activity Idaho Formal proceed- No activity ing in progress Illinois Informal inquiry, Study Authority 

retail wheeling granted by pilots SB 232, 

7/21/95 

Indiana Informal inquiry No activity Authority 

granted by SB 637, 4/26/95 

Iowa Formal proceed- Study 

ing in progress 

Kansas Informal inquiry Bill enacted Kentucky Informal inquiry No activity
Table 5. Status of Electric Industry Restructuring by State, as of June 30, 1996 (Continued)

State Competition Institutions Assets Investment Charge Energy Ratemakin

Regulatory Legislative

Overall Status

Type of New Generation Stranded Benefits Renewable Based

Transition

Costs/ System Performanc

72 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update Louisiana Formal proceed- No activity Wholesale and 

ing in progress retail (r) 

Maine Formal proceed- Bill enacted 

ing in progress 

Maryland Informal inquiry No activity Massachusetts Formal proceed- Bills under Wholesale and ISO, Power Functional Recovery Yes (r) Options being Yes (r) 

ing in progress, consideration retail (r) exchange (r) unbundling (r) allowed (r) considered (r) retail wheeling 

pilots Michigan Formal proceed- No activity ing in progress, retail wheeling experiment 

Minnesota Formal proceed- Study 

ing in progress 

Mississippi Informal inquiry Bill enacted Authority 

granted by HB 1130, 3/7/96 

Missouri Informal inquiry No activity Montana Formal proceed- No activity ing in progress Nebraska No activity Study Wholesale and Recovery Options (l) 

retal (l) allowed (l) 
Table 5. Status of Electric Industry Restructuring by State, as of June 30, 1996 (Continued)

State Competition Institutions Assets Investment Charge Energy Ratemakin

Regulatory Legislative

Overall Status

Type of New Generation Stranded Benefits Renewable Based

Transition

Costs/ System Performanc

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 73 Nevada Formal proceed- Study Optional 

ing in progress green pricing: 

SB 503, 6/29/95. Other acts promoting renewables: SB 267, 6/12/95; SB 504, 6/29/95; SCR 11. New Formal proceed- Bill enacted Wholesale and Functional Recovery 

Hampshire ing in progress, retail (r) unbundling (r) allowed (r) 

retail wheeling 

pilot 

New Jersey Formal proceed- Bill enacted Wholesale and ISO (r) Functional Authority 

ing in progress retail (r) unbundling, granted by S 

divestiture 1940, 7/20/96 required (r) 

New Mexico Formal proceed- Study Wholesale and 

ing in progress retail (r) 

New York Final decision Bills under Wholesale and ISO, Power Functional Recovery Yes (r) No explicit Yes (r) 

5/16/96, retail consideration retail (r) Exchange (r) unbundling (r) allowed (r) treatment wheeling pilots (r) 

North Carolina Informal inquiry No activity
Table 5. Status of Electric Industry Restructuring by State, as of June 30, 1996 (Continued)

State Competition Institutions Assets Investment Charge Energy Ratemakin

Regulatory Legislative

Overall Status

Type of New Generation Stranded Benefits Renewable Based

Transition

Costs/ System Performanc

74 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update North Dakota Informal inquiry No activity Ohio Formal proceed- Bills under Wholesale and Functional Recovery 

ing in progress consideration retail unbundling (l) allowed (l) 

(l) 

Oklahoma Formal proceed- Study 

ing in progress 

Oregon Informal inquiry Bill enacted Authority 

granted by H2846, 7/19/95 

Pennsylvania Formal proceed- Bills under 

ing in progress consideration 

Rhode Island Informal inquiry Bills under 

consideration 

South Carolina Informal inquiry No activity South Dakota No activity No activity Tennessee No activity No activityTexas Formal proceed- Bill enacted Wholesale 

ing in progress only (l) 

Utah Formal proceed- No activity

ing in progress 
Table 5. Status of Electric Industry Restructuring by State, as of June 30, 1996 (Continued)

State Competition Institutions Assets Investment Charge Energy Ratemakin

Regulatory Legislative

Overall Status

Type of New Generation Stranded Benefits Renewable Based

Transition

Costs/ System Performanc

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 75 Vermon t Formal proceed- No activity 

ing in progress 

Virginia Formal proceed- Bill enacted ing in progress Washington Formal proceed- No activity Wholesale (r) ing in progress West Virginia Informal inquiry No activity Wisconsin Final decision No activity Wholesale and ISO (r) Functional Recovery Yes (r) Green pricing Yes (r) 

retail (r) unbundling (r) allowed (r) (r) 

Wyoming Informal inquiry No activity Note: This table was prepared by the National Renewable Energy Laboratory, Washington, DC, under a contract with the Energy Information Administration. T

period ended June 30, 1996 ISO = Independent system operator. (r) = Regulatory. (l) = Legislative. Source: National Renewable Energy Laboratory.
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 77

 The emerging competitive market for electricity envisions that existing utility customers be able to secure power from alternative albeit lower-priced 170

suppliers. When this occurs, the utility that originally supplied power to a departing customer may not be in a position to market the power sold to the

departing customer to an alternative customer. The utility thus suffers a potential financial loss due to structural changes in the industry, leading to the creation

of what have commonly been called “stranded costs.” FERC’s definition of stranded costs has been provided in the preceding chapter. Additional discussion

is also provided in this chapter.

 Federal Energy Regulatory Commission, Order No. 888, Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission 171

Services by Public Utilities, Docket No. RM95-8-000, and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Docket No. RM-94-7-

001 (April 24, 1996), p. 451.

Ibid., p. 454 172

 Some other terms have also been used by analysts generally to describe stranded costs: strandable investments, stranded investments, stranded 173

assets, stranded commitments, or transition costs. Finer points of distinction can be made on the basis of asset valuation strategies adopted, changes in

customers’ status, or the financial consequences of moving a regulated industry to a competitive environment. FERC uses the “revenues lost” approach to

determine recoverable stranded costs (also called transition costs in the case of natural gas deregulation proceedings). The terms “stranded costs” and

“transition costs” are used interchangeably in this chapter even though their definitions are close but not necessarily congruent. Transition costs are stranded

costs charged to utility customers through some type of fee or surcharge after the assets are sold or separated from the vertically integrated utility.

 Cost of service is a ratemaking concept used in the design and development of utility rate schedules to ensure that the filed rate schedules recover 174

only the cost of providing electricity service. This procedure attempts to correlate the utility's cost and revenue with the service provided to each of the various

customer classes. The cost of service is synonymous with the concept of “revenue requirements.”

 Rate base signifies the value of property on which a utility is permitted to earn a rate of return established by a regulatory authority. It consists of 175

investments (generally valued at historical cost minus depreciation accruals) and other assets used in supplying service to customers. Depending on the

method used in its computation, the rate base consists of net plant valuations, cash, working capital and supplies (including fuel inventories), deductions for

accumulated provisions of depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and

accumulated deferred investment tax credits. 

 For economists, this method of price formulation equates prices (charged to customers) with average costs. Thus, average cost pricing has been the 176

dominant form of utility regulation.

8. Stranded Costs in Electricity Deregulation:

An Overview of Potential Mitigation Strategies170

Recovery of stranded costs is perhaps the most con- policies, mitigation strategies may be of relevance to them.

tentious issue confronting regulators in promoting These strategies, as discussed in this chapter, reallocate

competition in the electric power industry. Accordingly, costs among various segments of the economy.

this chapter looks at the possible options that can be used

to mitigate the level of stranded costs confronting utilities.

The potential impacts of implementing selected mitigation

strategies are also evaluated in the case of a hypothetical

utility using a financial model.

In its Order 888, the Federal Energy Regulatory Commission (FERC) reaffirmed its preliminary determination

“that the recovery of legitimate, prudent and verifiable

stranded costs should be allowed.” FERC's directive is 171

grounded in the belief that the recovery of stranded costs

is “critical to the successful transition of the electric

industry to a competitive, open access environment.”172

For this purpose, direct assignment of costs to departing

customers was selected as the appropriate method for

recovery of stranded costs. 

Stranded costs can arise in both wholesale and retail

transactions. Because retail competition is driven by State

Stranded Costs: Emergence and

Conceptualization173

Regulatory provisions under which the utilities currently

operate preclude the possibility of any prudently incurred

costs becoming stranded. State regulatory authorities

normally set electricity rates in such a way that electricity

prices the utilities charge reflect their cost of service.174

This is accomplished by setting prices at a level so that

total revenues equal total costs. Implementing this process

involves a review of a utility's operating costs, its rate

base, and the rate of return to be allowed on the rate

base. By adopting this process, the regulatory 175

authorities aim to protect the customer by setting the

prices charged to be just sufficient to cover prudently

incurred costs. Generally speaking, this process elimi- 176

nates any potential for encountering stranded costs.
78 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

 In this approach, all utility assets are valued on the basis of original costs, with adjustments made for depreciation. 177

 Assuming that the current utility franchised operations represent a monopoly, it is easy to see that monopoly prices will invariably be higher than 178

those likely to be determined under conditions of competition. There is, however, no implication that the utilities do charge monopoly prices. In fact, utility

regulation is designed to ensure that utilities do not earn monopoly profits but charge rates that are just and reasonable. Yet, there are a host of reasons why

prices charged by utilities in some areas may be higher than those that would prevail under competitive conditions.

 The converse is equally possible, implying that the market value of an asset may be higher than its historical cost valuation. In such cases, there will 179

be no “stranded costs” or “lost revenues.” In both cases, however, changes in income streams (other things being equal) cause corresponding changes in

the valuation of an asset.

 Within the above framework, the composition of stranded costs will be dominated by generating capacity. However, additional categories of costs 180

could also be included in the broader definition of stranded costs, as discussed later in this chapter. All costs included in the rate base are assumed to have

been prudently incurred.

 Niagara Mohawk Power Corporation filing with the New York Public Service Commission in PSC Case Nos. 94-E-0098 and 94-E-0099, Phase II, 181

Multi-Year Electric Rate, Restructuring and Retail Access Proposal (Syracuse, NY, October 6, 1995).

 See Appendix E, “Stranded Costs.” 182

In a competitive environment, the above conditions Order states that utilities may recover stranded costs only

change in a fundamental way. The basic difference stems if they are legitimate, prudent, and verifiable, and only if

from the manner in which assets are valued in the market. the utility mitigates the stranded costs by offsetting them

In a regulatory environment, utilities have the assurance by the market value of the power released by the

of recapturing asset values (adjusted for depreciation) departing customer. The methodology used by FERC in

based on historical costs. In a competitive market there estimating stranded costs is discussed in Appendix E. 177

is no comparable assurance, and historical asset costs are

of only marginal interest. Asset valuation is determined Utilities generally visualize a somewhat wider concept of

by current and future income streams. As an example, an what they call “strandable costs.” These include costs that

asset that does not produce any income (and has no would normally be recovered with the continuation of the

prospects of producing income in the future) has little or current regulatory cost-of-service rate-based regime but

no market value, regardless of its original cost. are otherwise in excess of the amount that they would

In the competitive environment, the possibility that prices transition is compensated. The main elements included

for electricity could be lower than those ordained in a in the wider concept of stranded costs are stranded assets,

regulatory regime becomes very real. This development stranded liabilities, regulatory assets, and stranded social 178

could, in turn, create a corresponding decline in income programs. Stranded assets refer primarily to those

streams, thereby causing a downward valuation of a investments in generation or related assets that would

given asset (or a group of them) in the market. This become uneconomic with the advent of competition and

phenomenon leads to what has commonly come to be which cannot be sold for some reason. Stranded liabilities

known as “stranded costs,” i.e., that unamortized portion are primarily contracts with unregulated generators but

of the original or historical cost of the plant which could also include contracts with fuel suppliers and

becomes unrecoverable under conditions of competitive contingent liabilities such as environmental remediation.

pricing of electricity. Regulatory assets are mainly deferred expenses that

The above example enables us to understand the concept regulatory promise that the utilities will be allowed to

of stranded costs. Stated in simplified terms, stranded recover them in the future. Stranded social programs

costs may be viewed as the excess of value (which is the include a variety of social programs that the utilities have

unamortized portion of historical cost outstanding on a undertaken voluntarily or otherwise by virtue of being a

utility's books) of assets over their market value in a regulated monopoly. Examples include the obligation to

competitive power market environment. Thus the provide universal service and to implement cross- 179

notion of stranded cost creation is based on the concept of subsidized pricing of services, environmental compliance,

costs that were prudently incurred to serve power and demand-side management expenditures. 

customers (within a regulatory environment) and which

cannot be recovered if the customers move to another

lower-cost supplier.180

As indicated in the previous chapter, FERC Order 888

recognizes the possibility of stranded costs associated with

wholesale and retail (including retail-turned-wholesale) Estimates of projected stranded costs vary widely, ranging

customers using open access transmission service. The from a low of $10 billion to $20 billion to a high of $500

recover in an environment of competition unless the 181

appear as assets for the balance sheet in return for the

182

Magnitude of 

Potential Stranded Costs
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 79

 “Comments” and “Reply Comments” submitted by the American Public Power Association in the matter of “Recovery of Stranded Costs by Public 183

Utilities and Transmitting Utilities” before the Federal Energy Regulatory Commission on December 6, 1994, and January 23, 1995, respectively.

 For a discussion of what the range of estimates really means, refer to Oak Ridge National Laboratory, Estimating Potential Stranded Commitments 184

for U.S. Investor-Owned Electric Utilities, ORNL/CON-406 (Oak Ridge, TN, January 1995), pp. 3-6. 

 National Economic Research Associates, Rewriting the Rules of the Road: Retail Wheeling and Competition in Electric Generation (New York, 185

NY, March 1994).

 Defining break-even price as the minimum price that a utility must charge to fully recover its fixed production costs, Moody's estimates the difference 186

between a utility's break-even price and the market price for that capacity. Multiplying the difference by the total of a utility's capacity enables the derivation

of stranded costs for any given year. These projections are extended for a 10-year period and then appropriately discounted to yield a net present value. For

additional details see Moody's Investor Service, Stranded Costs Will Threaten Credit Quality of U.S. Electrics (New York, NY, August 1995).

 National Regulatory Research Institute, The Regulatory Treatment of Embedded Costs Exceeding Market Prices: Transition to a Competitive 187

Electric Generation Market—A Briefing Document for State Commissions (Columbus, OH, November 1994), p. 8. 188 M. D. Yokell, D. Doyle and R. Koppe, “Stranded Nuclear Assets and What to Do About Them,” presentation to the DOE-NARUC Electricity Forum

(Providence, RI, April 1995).

 See J. H. Wile, “What Do You Mean My Stranded Costs Are Uncertain?” presentation made to the Financing the Future of the Electric and Gas 189

Industries Conference (Chicago, IL, July 25, 1996).

billion, depending on the assumptions and methodology the “industry estimate seems to grossly overestimate the

used. The low estimates of stranded costs are attributable reduction in the value of utility assets.” 

to the American Public Power Association (APPA). APPA

claims that about 5 to 10 percent of the capacity assets of There is, however, no implication that projections of

the investor-owned utilities may become stranded. The stranded costs at the lower end of the spectrum are more 183

high estimates come from many sources, including the realistic than those at the upper end. For the most part, all

Edison Electric Institute, Resource Data International, estimates have been made under the proverbial “what if”

National Economic Research Associates (NERA), and conditions brought about by differences in perspective.

others. Some of these estimates include other elements of The yet-to-evolve characteristics of the market, the role of

costs (liabilities associated with power purchase contracts, its new players, and the level of future natural gas prices

regulatory assets, and others) that have the potential to be are all unknowns. In addition, the availability of reliable

stranded. data with respect to the unamortized costs (or 184

 investments) together with related plant operating data

NERA, for example, estimates the stranded costs to be the pose another nontrivial estimation problem. Any of these

difference between the short-run marginal costs of factors, singly or jointly, can cause serious biases in

generation (in the range of 2 to 3 cents per kilowatthour) projecting stranded costs. 

and the average cost (in the range of 5 cents per

kilowatthour) for an unknown time period, so that its In addition, there are those who seriously believe that a

estimate of $500 billion is at the upper end of the spec- major segment of stranded costs may be attributable to

trum. Moody's Investor Service’s (Moody's) estimate of domestic nuclear power plants. According to one study, 185

total stranded costs for the investor-owned utilities is in of the nearly $120 billion in undepreciated assets in

the range of $50 billion to $300 billion, depending on domestic nuclear power plants, nearly 60 percent (or

market price assumptions. However, Moody's most likely about $70 billion) may be “stranded” in a competitive

scenario estimates stranded costs to be $135 billion, with environment. It is possible that these estimates are not

the highest concentration of costs among the utilities in the only influenced by uncertainties with respect to the future

Northeast and the West accounting for more than 40 but also by the assumption that the affected utilities may

percent of the industry's total stranded costs. not be able to take any action to correct observable cost 186

Variances in available estimates of stranded costs stem

from the assumptions made with respect to critical A more recent study (assuming that deregulation and

variables in the process. Assumptions that significantly restructuring of the industry would be completed by the

affect projected levels of stranded costs include the share end of 1996) estimates the nuclear investment at risk to be

of retail electricity sales subject to competition, the $63 billion if the competitive markets take effect at the

projected market clearing price of electricity, and the beginning of 1997. In the more likely event that

number of years used in computing stranded investments. restructuring is fully effected by the year 2000, the at-risk

Higher estimates of stranded costs may be linked with investment in nuclear power plants would decline to $43

more pessimistic perspectives regarding utilities’ loss of billion and to $10 billion for the 2010 time frame. The

market share or their lack of resilience in the adjustment postulated time period for the industry's transition is,

process to lower the price or find alternatives to sales of therefore, another critical variable in the estimation of

at-risk capacity. Accordingly, some analysts contend that potential stranded costs or investment at risk.

187

188

imbalances within the foreseeable future.

189
80 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

 The long-run marginal costs are defined by the levelized costs associated with either a 200-megawatt dual-fired combined-cycle unit, with efficient 190

heat rate and low operating costs, or a 200-megawatt coal unit with access to cheap western coal. The volume of demand at risk was approximated by the

size of the industrial load.

 The net present valuation asset estimation assumes that assets are stranded in equal proportions over the 1997-2002 period. 191

 Federal Energy Regulatory Commission, Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Docket No. RM94-7-000 192

(Washington, DC, June 29, 1994). 

Ibid., p. 321. 193

Another study comes up with estimates nearly the same or will take reasonable and prudent measures to mitigate

as the above but for reasons that differ slightly. Data stranded costs. Although FERC received support for

Resources Incorporated (DRI) has come up with estimates requiring that mitigation measures be taken, there is

of stranded costs for each Census division, based on the prevailing ambivalence on how to adopt mitigation

difference between the region's industrial electricity price measures for them to be effective and how to deal with

(less transmission and distribution costs) and the long-run those stranded costs that are difficult to mitigate. In

marginal generation cost, multiplied by the volume of issuing Order 888, FERC upheld the view that its

electricity demand expected to be at risk in the region “revenues lost” approach for determining stranded costs

(Table 6). The amount of stranded assets is estimated encompasses mitigation measures. Since this aspect will 190

at $88 billion, with their net present valuation being $67 be critically examined in the future, mitigation options

billion. The distribution of these assets is quite po- that are available need to be carefully examined. 191

larized, with New England and California being at

maximum risk for one-third to one-half of their rate base.

At the other extreme are low-cost regions with no assets at

risk (Table 7 and Figure 14). 

Detailed descriptions of different approaches to estimating stranded costs are contained in Appendix E. How to address stranded costs has become a critical issue

Mitigation Requirements in 

Recovery of Stranded Costs 

Under the FERC’s procedures, a utility seeking to recover designed to reduce the burden that utilities and their

its stranded costs will be required to show that it has taken shareholders will otherwise be required to shoulder. 

192

193

Mitigation Strategies To Address

 Stranded Costs

in promoting competition in the electricity industry.

FERC’s Mega-NOPR provides a discussion of the options

suggested by utilities, regulators, and other interested

parties that could be used in mitigating the level of

stranded costs likely to confront a utility. These strategies

are more commonly known as “mitigation” strategies

Table 6. Average and Marginal Cost of Electricity Production by Census Division, 1995

(Cents per Kilowatthour)

Census Region Marginal Cost Average Electricity Price Difference

New England . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9 9.9 -5.9

Pacific 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 9.2 -5.0

Middle Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9 9.2 -5.2

Mountain 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8 7.7 -3.9

South Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9 6.4 -2.5

East North Central . . . . . . . . . . . . . . . . . . . . . . . . 3.9 6.0 -2.1

West North Central . . . . . . . . . . . . . . . . . . . . . . . 3.7 5.8 -2.1

East South Central . . . . . . . . . . . . . . . . . . . . . . . 3.7 5.3 -1.6

West South Central . . . . . . . . . . . . . . . . . . . . . . . 3.8 6.1 -2.2

Mountain 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8 5.5 -1.7

Pacific 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8 4.2 -0.3

 Source: DRI/McGraw Hill, World Energy Service—U.S. Outlook: Fall/Winter 1996 (Lexington, MA, 1996), p. 44.
West 

North Central

2.7 East 

North Central

0

New England

16.6

South Atlantic

12.2

Middle Atlantic

21.5

East

South Central

7.5

West South Central

0

Mountain 2

3.4

Mountain 1

0

Pacific 1

0

Pacific 2

24

Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 81

 Source: DRI/McGraw Hill, World Energy Service—U.S. Outlook: Fall/Winter 1996 (Lexington, MA, 1996).

Figure 14. Estimates of Stranded Costs by Census Division, 1995

(Billion Dollars)

Table 7. Regional Distribution of Stranded Costs by Census Division, 1995

Stranded Costs Stranded Costs Rate Base a

Present Value of Share of Current

Present Value as

Billion Dollars Percent

New England ............................... 16.6 12.7 59

Middle Atlantic .............................. 21.5 16.5 24

South Atlantic ............................... 12.2 9.3 13

East North Central . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0

West North Central . . . . . . . . . . . . . . . . . . . . . . . . . . 2.7 2.0 8

East South Central . . . . . . . . . . . . . . . . . . . . . . . . . . 7.5 5.8 35

West South Central . . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0

Mountain 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0

Mountain 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4 2.6 18

Pacific 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0

Pacific 2 ................................... 24.0 18.4 54

 U.S. Total ................................ 87.8 67.3 17

 Stranded costs by region are estimated by DRI based on the difference between the region’s average industrial electricity price and a

the cost of new generation. This approach misses stranded costs associated with high-cost generating plants in regions dominated

by low-cost generating plants, such as East North Central, West South Central, Mountain 1, and Pacific 1. While stranded costs may

not be zero in these regions, they are expected to be significantly lower than in the coastal regions.

 Source: DRI/McGraw Hill, World Energy Service—U.S. Outlook: Fall/Winter 1996 (Lexington, MA, 1996), p. 44. 
82 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

 Federal Energy Regulatory Commission, Notice of Proposed Rulemaking and Supplemental Notice of Proposed Rulemaking (March 29, 1995). 194

The NOPR is made up of two dockets: (1) Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public

Utilities, Docket No. RM95-8-000, and (2) Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Docket No. RM94-7-001.

An important caveat, in connection with the adoption of These strategies are applied to a hypothetical utility and

strategies to mitigate stranded or transition costs, should their impact is assessed by using a financial model—

be kept in mind. Stranded costs, to the extent that they ORFIN (Appendix D). The assessment process involves

reflect sunk costs or obligations, cannot by definition be incorporating a specific strategy into a planning and

mitigated. Thus, nearly all the “mitigation” strategies aim production costing model to estimate the resulting

to shift stranded costs among differing segments of the financial consequences. Data for an actual utility facing

economy. The potential candidates for absorbing all or a substantial strandable costs were used for this hypoportion of the stranded costs include the utility thetical analysis. The estimate of each strategy's effect

shareholders, ratepayers, taxpayers, wheeling customers, is the difference in strandable costs (or transition costs)

or independent power producers (including qualifying due to retail competition with and without the strategy. 

facilities [QFs]). In some cases, suggestions have been

made for the State or the Federal Government to bear Reasonably complete representations of various selected

these costs in some manner. strategies were incorporated in the model to evaluate their

It should also be noted that not all the mitigation

strategies that have been discussed or recommended in

the past are based on considerations of equity or fairness

when it comes to deciding who should bear the burden of

stranded costs. The basic intent is to lower or reduce the

level of stranded costs that utilities may otherwise be

required to absorb. As indicated in the previous chapter,

FERC favors the notion that a utility be allowed to recover

its stranded costs subject to providing evidentiary

demonstration that “it has taken and will take reasonable

and prudent measures to mitigate stranded costs.”194

FERC recognized that failure to deal with the stranded

cost problem could delay the transition to a fully

competitive, open access environment. It could also

destabilize the financial integrity of the industry. In a

sense, FERC legitimized the notion of adopting mitigation

strategies as being an integral part of the recovery

mechanism.

The above developments explain the growing interest in

developing mitigation strategies that can be used to lower

the utilities' burden in absorbing stranded costs. These are

discussed next. Note that difficulties arise in providing a

comparative evaluation of mitigation strategies in the

absence of a fully developed analytical background.

Results of Mitigation Strategies

Since the release of FERC’s stranded costs NOPR in 1994,

interest in developing mitigation strategies has intensified.

A discussion of all mitigation strategies developed since

then is provided in Appendix E. 

impacts with a view to distinguish between strategies that

may have large effects from those with smaller effects.

Mitigation strategies selected included market options,

depreciation options, ratemaking options, utility cost

reduction options, and other approaches.

If retail competition began in 1996, and by 1998 60 percent

of this utility’s commercial and industrial customers

choose alternate suppliers, net present value of this

utility’s stranded costs are estimated to be $2.45 billion,

representing 77 percent of the firm’s 1995 equity.

Mitigation strategies will alter the utility’s losses. Subject

to the above observations, the following summary results

were obtained. 

Strategies with Large Impacts

 For at-risk utilities, delaying retail wheeling,

charging exit fees to departing customers, reducing

administrative and general costs, and discounting

QF energy payments are all likely to result in large

reductions of 25 percent or more in the base case

utility's stranded costs (i.e., more than $600 million).

As an example, delaying retail wheeling by 2 years

reduces the strandable costs by $790 million. 

 The nongeneration cost reduction potential (as

applied exclusively to the specifics of the hypothesized base case utility) is found to be high,

exceeding $1.0 billion. Possibilities of securing additional reductions are also identified in areas of the

base case utility’s nongeneration costs (e.g., customer service, operations and maintenance related

to transmission and distribution) primarily because
Energy Information Administration/Changing Structure of the Electric Power Industry: An Update 83

 For the sake of simplicity, the Oak Ridge study assumes that the customers pay an exit fee the year they take wheeling service. An algebraic 195

formulation computes the net present value of the exit fees for different customer classes, depending on the year they leave, with the end point for all customer

classes being 2018. Two variations of the exit fees are calculated: (1) the difference between total generation and market generation costs is kept constant

over time, and (2) the difference is allowed to change over time. 

 The hypothesized base case utility has an abundance of power-purchase contracts without dispatchability provisions. Actions that the utility takes 196

to reduce these costs, particularly the energy payments, through renegotiation or buyout of these contracts will have significant impacts on its strandable costs.

The ability to sustain long-term nondispatchable power-purchase contracts with fixed payments well above current or anticipated market prices is a major

issue confronting the industry.

 The base case utility pays an average price of 7.2 cents per kilowatthour for its power purchases, as compared with the average market price of 2.5 197

cents per kilowatthour. 

 Strategies to lower the costs of purchased power entail some form of resistance from independent power producers, which may not always be possible 198

to eliminate but can be moderated. 

of its comparatively higher costs in comparison with Power purchase contracts could be renegotiated with

benchmark performance data. regard to payments for capacity or energy. Other options

 Rapidly opening retail markets increases the level of run” provisions or an outright buyout. Depending on the

strandable costs significantly. If the assumption that nature of the strategy adopted and the longevity of the

all retail customers wheel from alternative sources power purchase contract obligations, the savings could be

by the year 2000 is incorporated in the ORFIN large, exceeding the base case utility's total transition

model, this strategy increases transition costs to $4.8 costs.

billion. 

 Imposing exit fees (of one kind or another) on

departing wholesale and retail customers is a

strategy that has wide support. The exit fees can be

computed as a one-time charge or could be structured as a stream of payments. Assuming that the 195

exit fees are paid in a lump sum when the customers

leave the system, the impact can be substantial. The

Oak Ridge study (which uses two approaches in

estimating exit fees) indicates that nearly all the

stranded costs can be met from the proceeds of exit

fees, with net gains resulting under more optimistic

conditions.

 The effects of a utility’s marketing energy freed by

the departing retail customers are difficult to assess,

with the result that transition costs can go down

modestly or increase significantly. The benefits (or

costs) of marketing excess energy (for the base case

utility) are related to the marginal generation costs

of the utility's own plants and operations, the cost

obligations of its power purchase contracts, and the

characteristics of the wholesale market. Utilities

with substantial transmission capacity will find

marketing to be a more effective strategy than will

utilities without sufficient interconnections.196

 Strategies to discount or reduce power purchase

costs potentially produce large cost reductions primarily because the base case utility has must-run

power purchase contracts at costs that are significantly higher than the average market costs. 197

include substituting dispatchability in lieu of the “must198

Strategies with Medium Impacts

 Strategies with medium effects (reflecting changes

from 5 to 25 percent, i.e., $120 million to $600

million) that potentially reduce strandable costs

include imposition of charges for ancillary services;

reductions in customer-service costs, transmission

and distribution operating and maintenance (O&M)

costs, and generation O&M costs; and discounting

QF capacity payments to market. 

 A strategy to accelerate depreciation payments (of

generation plants) can have significant effects on

stranded costs, particularly if the policy is pursued

in isolation. 

 The absolute effects (positive or negative) of increasing system load factors depends on the magnitude of load factor changes. Attempts to reduce onpeak demand may reduce revenues, whereas

increasing off-peak sales may increase revenues.

Strategies with Modest Impacts

 The strategy of reducing public policy programs has

only modest effects (i.e., where changes are less than

5 percent or less than $120 million) on transition

costs, depending on the size of initial programs and

the extent of the reductions. 

 The impact of offsetting increased cost of accelerated

depreciation by decelerating the depreciation of
84 Energy Information Administration/Changing Structure of the Electric Power Industry: An Update

other assets depends on when the change begins. If successful implementation. Accordingly, who should

the change is initiated before the commencement of share how much of the anticipated burden is likely to be

retail wheeling, strandable costs decline. In the decided by a consensus approach among the various segalternative, strandable costs are likely to increase. ments of the economy, again including the regulators.

Similar timing considerations apply with respect to Utilities may or may not be able to recover all that they

the acceleration of regulatory assets. may want to include in stranded cost computations, but

Concluding Remarks

Most of the strategies examined here require the tacit cooperation of other parties, including the regulators, for

recent developments in California and Rhode Island offer

encouragement. The operational impact of policies permitting stranded cost recovery (at the State or Federal

level) may be to provide a reasonable period of transition

to ensure the financial integrity of the industry. Electricity

supplies and deliverability could thus be assured for the

future.
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 85

 Energy Information Administration, Financial Statistics of Major U.S. Investor-Owned Electric Utilities 1995, DOE/EIA-0437(95/1) (Washington, 199

DC, December 1996).

Note: Totals may not equal sum of components due to

independent rounding.

Source: Energy Information Administration, Financial

Statistics of Major U.S. Investor-Owned Electric Utilities

1995, DOE/EIA-0437(95/1) (Washington, DC, December

1996).

Figure 15. Allocation of Revenue Dollars from

Electric Operations for Major U.S.

Investor-Owned Utilities, 1995

9. Transitional Developments and Strategies:

The Industry Prepares for Competition

As has been described in the preceding chapters, many

changes in the structure and operations of the electric

power industry are now taking place. This chapter discusses the actions that different segments of the industry

are taking to prepare for the future and some of the new

developments in the industry. It is intended to provide a

snapshot of an industry undergoing significant change

that probably will extend into the next century.

Investor-Owned Utilities

For more than a century, vertically integrated investorowned utilities (IOUs) have produced and sold most of

the electricity in the United States. In 1995, they accounted for about 75 percent of retail and about 40

percent of wholesale electricity sales. As competition 199

increases, however, their dominant position is being

challenged. New generating capacity can be built and

operated at prices substantially lower than the price of

some electricity sold by electric utilities, and open

transmission access will give electricity customers more

choices of wholesale electricity suppliers. As a result,

high-priced suppliers will lose customers to low-priced

suppliers.

To stay competitive and to prepare for a future industry

that will be very different from the past, IOUs are looking

for ways to lower their electricity prices. The average

price of electricity is based on the utility’s cost of service,

which usually includes a return on capital. In 1995, IOUs

received $184 billion in electric operating revenues, which

covered operating and maintenance expenses (O&M),

depreciation and amortization expenses, and Federal and

State taxes (Figure 15). The remaining revenues were

operating income, used to pay interest on long-term debt,

to pay dividends to investors, and to save as retained

earnings. Since almost 57 percent of the revenues were

used to pay for O&M activities, including fuel, keeping

these expenses under control is important in maintaining

competitive electricity prices. In that regard, IOUs are

taking specific actions to lower O&M expenses. Staff

reductions are the most visible cost-cutting strategy. Some

companies are merging, or planning to merge, to

eliminate redundant functions and to obtain synergies.

General Trends in Operating and

Maintenance Expenses of Investor-Owned

Utilities

O&M activities in the electric power industry—which

totaled $104 billion in 1995—include power production,

power purchases, transmission and distribution of power,

customer services, and administrative and general acti-
86 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 Energy Information Administration, Cost and Quality of Fuels For Electric Utility Plants 1994, DOE/EIA-0191(94) (Washington, DC, July 1995). 200

 “Duke Expects $13.6-Million Savings From One-Year Buy-out of Coal Pact,” Electric Utility Week (August 28, 1995), p. 10. 201

 “Centerior Retiring Three Coal Plants, Eliminating 500 Jobs To Cut Costs,” Electric Utility Week (May 20, 1996), p. 3. 202

Figure 16. Allocation of Electric Operation and

Maintenance Expenses of Major U.S. 

Investor-Owned Utilities, 1995

 Source: Energy Information Administration, Financial

Statistics of Major U.S. Investor-Owned Electric Utilities

1995, DOE/EIA-0437(95/1) (Washington, DC, December

1996).

vities. In 1995, power production accounted for almost 45 market. For example, Duke Power estimated a net saving

percent of O&M expenses, followed by power purchases of about $13.6 million from a buyout of its coal supply

at nearly 29 percent and administrative and general and contract with Westmoreland Coal Company. Officials at

customer service and sales expenses at 19 percent (Figure Duke Power were confident that coal could be purchased

16). This distribution illustrates how O&M expenses are under short-term contracts or in the spot market at prices

allocated among the activities of the company; however, well below those in the contract. Other utilities were

with more price competition likely, it is important to have able to reduce the costs of transporting coal to their plants

a downward trend in these expenses. As a group, IOUs by renegotiation of contracts or by taking advantage of

have achieved some success in lowering costs. Real O&M increased competition among the carriers. Increasing

costs have decreased by 22 percent from about 4.5 cents purchases of low-cost western coal also helped reduce fuel

per kilowatthour (kWh) in 1986 to 3.5 cents per kWh in costs for coal-fired plants. 

1995 (Figure 17). Lower fuel prices accounted for most of

the reduction in O&M expenses. Over the same years, Besides coal, the costs of other fuels have decreased over

non-fuel O&M costs were relatively stable at about 2.6 the past few years. Average wellhead prices for natural

cents per kWh, indicating perhaps that more effective gas have generally declined from 1987 through 1994, with

non-fuel cost reduction activities are needed. a brief upward trend in 1992 and early 1993. Gas-fired

Lower coal prices, brought about by excess coal United States. A large worldwide surplus of uranium has

production capacity and changing market conditions, also caused its prices to decrease over the past decade or

provided the largest reduction in industry fuel costs. more. Nuclear plants, which use enriched uranium, pro- 200

With more than 55 percent of the electricity generated in duce about 22 percent of the electricity in the United

the United States coming from coal-fired plants, lower States.

coal prices make a big difference in average fuel costs. As 

coal prices dropped, many utilities found it economical to In addition to lower fuel costs, many IOUs have

“buy out” older, more expensive contracts and increase significantly reduced their workforce and lowered their

purchases under newer, less expensive contracts, or to payroll expenses through attrition, early retirement, and

increase purchases of less expensive coal from the spot voluntary and involuntary severance. From 1986 to 1995,

201

plants produce about 10 percent of electricity in the

employment at major IOUs decreased by about 20

percent, a reduction of more than 100,000 employees

(Figure 17). Real salaries and wages decreased by 28

percent, from about 0.7 cent per kWh in 1986 to about 0.5

cent per kWh in 1995 (Figure 17).

In an increasingly competitive industry, staff reductions

and downsizing are likely to continue. Many utilities

have announced plans to revamp their organizational

structures, streamline operations, and reduce staff.

CINergy—a holding company of Cincinnati Gas and

Electric and PSI Energy with a combined total of over

7,300 electricity-related employees—plans to cut its

workforce by 5 percent through retirement and severance

arrangements. Another holding company, Centerior

Energy— which includes Cleveland Electric Illuminating

and Toledo Edison and has a combined total of more than

5,400 electricity employees—is planning to retire three

coal plants and eliminate 500 jobs, or 9 percent of its

electricity employment. Centerior officials have said that

these actions are part of a company program to reduce

costs and to improve its competitive position.202
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 87

 The per-kilowatthour cost of purchased power is computed using total net energy generated and received. This reflects the increasing role of high 203

cost purchased power relative to energy generated by the utility. The actual cost of purchased power has been decreasing, but it is still higher than the cost

of utility-generated electricity. In 1995, the average direct cost of purchased power was 3.94 cents per kWh compared to 3.29 cents per kWh for utilitygenerated electricity.

Operation and Maintenance expenses of major IOUs

decreased from 4.5 cents per kWh in 1986 to 3.5 cents per

kWh in 1995. Declining fuel costs are the main reason for

lower O&M costs.

Over the last decade, major IOUs have reduced employment

by about 100,000.

With employment cuts, salary and wage expenses

decreased, but the savings were offset by increases in

power purchases and administration and general expenses.

Purchases of electricity increased to about 25 percent of the

total electricity available for sale in 1995. Purchases from

nonutilities increased to 7 percent of the total.

Source: Energy Information Administration, Financial Statistics of Major U.S. Investor Owned Electric Utilities 1995,

DOE/EIA-0437(95/1) (Washington, DC, December 1996), and previous issues.

Figure 17. Trends in Operation and Maintenance Expenses of Investor-Owned Utilities, 1986-1995

Utilities, relying more on purchased power now than in O&M costs attributable to purchased power has increased

the past to meet their power needs, are finding that the steadily since 1988, reaching a high of almost 1.0 cent per

relatively high cost of purchased power hinders their kWh in 1992, where it has remained through 1995 (Figure

efforts to reduce O&M costs. In the late 1980s, IOUs 17). Some industry analysts believe that the requirepurchased about 16 percent of their power needs, ment in the Public Utility Regulatory Policies Act

compared with more than 25 percent in 1995. The share of (PURPA) for utilities to purchase electricity from qualified

203
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

50

100

150

200

250

300

350

Number of Companies

Major Investor-Owned Utility Total Investor-Owned Utility

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

 “ PP&L to Pay $91 Million to NUG Plant To Stop Buying 100 MW Under Old Pact,” Electric Utility Week (March 4, 1996), p. 4. 204

 “Independent Electric Producers Losing Power Struggle,” Wall Street Journal (August 15, 1996). 205

 Although there were 244 operating companies in 1995, consolidation is greater than the numbers indicate. Some of these operating companies are 206

subsidiaries of holding companies. For example, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric and Power are

subsidiaries of the Southern Company, a registered holding company.

 Major investor-owned utilities are defined as having in the past 3 consecutive years one or more of the following: (1) 1 million megawatthours of 207

annual sales, (2) 100 megawatthours of annual sales for resale, (3) 500 megawatthours of annual power exchanges delivered, or (4) 500 megawatthours of

annual wheeling for others.

 Source: Energy Information Administration, Financial

Statistics of Major U.S. Investor-Owned Electric Utilities 1995,

DOE/EIA-0437(95/1) (Washington, DC, December 1996), and

previous issues.

Figure 18. Number of Investor-Owned Electric

Utilities, 1986-1995

independent power producers at the avoided cost of By creating a larger customer base, more control of

production caused, at least in part, these costs to escalate. transmissions lines, or lower average costs, a merger can

Many utilities are now finding that their avoided costs are potentially strengthen the resulting company in several

less than originally anticipated, and they are challenging ways. Articles reporting that utility executives have met

the contracts signed in the early days of PURPA. to discuss the possibility of merging appear fairly

Some utilities are trying to buy out existing purchase

contracts in order to reduce costs. For example, Pennsylvania Power and Light (PP&L) will pay $91 million to

a nonutility generator to terminate its contract for 100

megawatts of capacity from a coal gasification project.

Because the original contract was signed in 1985, when the

utility’s avoided costs for power were higher than today’s

costs, PP&L claims that, even at this high buyout price, it

will save $114 million over the next 13 years. Perhaps 204

a more visible example is the Niagara Mohawk buyout, in

which Niagara offered to buy out contracts from 19 of its

largest independent suppliers and indicated that if the

public utility commission failed to make some concessions

on the independent suppliers’ contracts, the company

might file for bankruptcy.205

Administration and general (A&G) expenses have also

increased over the past few years, reaching almost 0.5 cent

per kWh in 1994 (Figure 17). In 1995, they decreased to

about 0.4 cent per kWh. Higher-than-normal employee

pensions and benefit expenses, caused by large staff

reductions with expenditures for early retirement

bonuses, employee buyouts, and employee severance

pay, are responsible for most of the fluctuation in these

expenses. In 1994, for example, major IOUs spent more

than $5.4 billion (38 percent of total A&G expenses) on

pensions and employee benefits, decreasing to $4.2 billion

(33 percent of total A&G expenses) in 1995. With more

staff reductions planned, however, it is expected that these

expenditures will be high for the near future, and then

decrease as utilities complete their downsizing activities.

Mergers and Acquisitions of InvestorOwned Utilities

A second way in which IOUs plan to improve their

competitive position is through mergers and acquisitions.

frequently in recent editions of newspapers and trade

journals. The motives, according to utility executives, are

to combine resources, eliminate redundant operations,

and reduce costs, all of which are necessary to stay

competitive.

Mergers are not new to the electric power industry. Over

the past 10 years, 38 electric IOUs have merged with other

utilities in the industry. In 1986 there were 282 IOUs, of

which 182 were “major” IOUs. By 1995, there were 244

IOUs remaining, of which 179 were major IOUs (Figure

18). It appears that the trend of IOU consolidation is 206 207

continuing, and that major IOUs are getting larger by

merging with smaller utilities.

In the United States, it is fairly common for private

companies to merge with or acquire other companies. A
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 89

 This discussion refers to a merger or acquisition of corporations in the same line of business—horizontal merger or acquisition. Vertical mergers or 208

acquisitions, which combine companies of different product lines, are not discussed, although this type of merger occurs frequently in the United States.

 Information on mergers from 1936 through 1985 were obtained from the National Regulatory Research Institute, “Electric Utility Mergers and 209

Regulatory Policy,” Occasional Paper #16 (June 1992).

 R. Pierce, “Antitrust Policy in the New Electricity Industry,” Energy Law Journal (1996), pp. 29-58. 210

 “PEPCO to Merge With Baltimore Gas & Electric,” The Washington Post (October 1995). 211

 “Utilities’ Merger Creates Another Power House,” Chicago Tribune (August 15, 1995). 212

 R. Michaels, “Electric Utility Mergers: The Wrong Strategy at the Wrong Time,” The Electricity Journal (January/February 1996). 213

company seeking to improve its operating efficiency, mergers are completed, each new company will have

increase its market share and profits, or expand its assets of over $4.0 billion, and three of the nine will have

product line may find that it can accomplish one or more assets of over $10.0 billion.

of these goals through a merger. IOUs share these broad

goals, and many of them have merged with or acquired Consolidation of IOUs is not necessarily an ominous

other utilities to help meet their business objectives. The trend. The structure of the industry varies greatly by State

electric utility industry has a long history of mergers, and region, and in some regions it is fragmented. In parts

starting in the early 1900s. From 1917 through 1930, of the Midwest, a single large IOU serves millions of 208

consolidations of electric utilities were more common than consumers in several States, while in parts of New

at any other time in the history of the industry. They England, several tiny IOUs serve portions of a single small

occurred at a rate of more than 200 per year, peaking at State. One school of thought holds that in locations where

over 300 per year in the mid-1920s. Most of the mergers fragmentation and overlapping service exist, conso- 209

in the 1920s combined small operating companies into lidation would improve the efficiency of companies. 

large holding companies. In the early 1930s many of the Utility executives seeking approval of mergers adopt this

holding companies collapsed financially. The Federal line of thinking, claiming that by combining resources

Trade Commission (FTC) investigated the situation and significant costs saving will be realized. Executives from

uncovered a host of financial abuses. The investigation Baltimore Gas & Electric and Potomac Electric Power

led to the passage of the Public Utility Holding Company Company claim that by merging, many duplicate efforts

Act of 1935 (PUHCA), which mandated that the will be eliminated, the work force will be reduced by

operations of each affected holding company be limited to about 10 percent, and they will save $1.3 billion over

a single integrated public utility system. Between 1935 about 10 years. Similarly, Union Electric and Central

and 1950, more than 750 utilities were spun off from the Illinois Public Service plan on saving $570 million in 10

holding companies. Following the breakup of large years by trimming duplicate corporate and administrative

holding companies, consolidations continued, but at a programs, reducing production costs, and cutting about

much lower annual rate. From 1936 through 1975, there 300 jobs through attrition. Northern States Power and

were 517 mergers, occurring at an annual rate of less than Wisconsin Energy Corporation estimate that they will

15 a year. Over the past 20 years, 1976 through 1995, 66 realize $200 million in annual savings, mostly from reducmergers have taken place, about 3 per year on average. tions in staff. In every recent announcement, cost

In many cases, mergers of electric utilities occurring over ging, and the biggest source of savings is the consolidation

the past decade have been different from those that of duplicate personnel and facilities in the unmerged

occurred previously. Many of the latest round of companies.

mergers—“mega-mergers” as they are sometimes

called—combine large companies (Table 8). For example, Critics claim that savings from mergers are overstated,

in 1988 the Southern Company acquired Savannah and that only small cost reductions ever materialize. A

Electric Power, achieving combined assets of $27.0 billion. quick look at two mergers occurring in 1992 indicates that

 In 1989, the merger of Pacific Power and Light and Utah this criticism is sometimes but not always accurate. In the

Power & Light resulted in centralized management of 2 years following the merger of Iowa Power and Iowa

electric power over a region covering seven States, with Public Service, O&M costs of the merged company

assets of $10.3 billion. More recently, the 1993 merger of increased from about $28 per megawatthour (MWh) to

Gulf States Utilities with the Entergy Corporation (a regis- over $30 per MWh (Figure 19). Employment in the years

tered holding company) created a company with more following the merger decreased slightly, but salaries and

than $22 billion in assets. CINergy Corporation, the wages rose by about 18 percent. Part of the reason for the

newest registered utility holding company in the United increase in costs was a reduction in electricity sales for the

States, is a combination of Cincinnati Gas & Electric and merged company, without a proportional decrease in total

PSI Resource, with combined assets of $8.1 billion. At last O&M expenses. Electricity sales went from 13.9 million

count, there were nine mergers pending. When the MWh in 1992 to 12.1 million MWh in 1994, a decrease of

210

211

212

213

savings are cited as the most important reason for mer-
90 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Table 8. Mergers and Acquisitions of Investor-Owned Utilities, 1986-1995

Merger Partner or Merger Partner or Name of Combined Assets

Acquiring Utility Utility Being Acquired New Company

1994

(Billion Dollars)

1986

Lynches River Electric Coop ....... Heath Springs Light and Power -- Unknown

Northern States Power (MN) ....... Home Light and Power Co. (MN) -- 5.6

Public Service Co. of Colorado ..... Home Light and Power Co. (CO.) -- 4.3

Northern States Power Co. (WI) .... Lake Superior District Power Co. (CO) -- 0.8

Consolidated Edison Co. of N.Y. . . . Lawrence Park Heat, Light, & Power Co. -- 14.2

Iowa-Illinois Gas and Electric Co. . . . Sherrard Power Systems -- 1.5

PacificCorp .................... Svilar Light & Power Co.,Inc. -- Unknown

Cleveland Electric Illuminating ..... Toledo Edison Centerior 10.7 b

1987

Pennsylvania Electric Co. ......... Elkland Electric Co. -- 2.4

The City of Troy, MT. ............. Montana Light and Power -- Unknown

Bangor Hydro-Electric Co. ........ Stonington & Deer Isle Power Co. -- 0.4

UtiliCorp United ................. West Virginia Power -- 3.1

West Kootenay Power & Light --

1988

Appalachian Power Co. .......... Chesapeake Light & Power Co. -- 3.7

Monongahela Power Co. ......... Preston Electric Co. -- 1.5

Duke Power ................... b Nantahala Power & Light -- 12.9

Southern Co. .................. a Savannah Electric & Power -- 27.0

1989

Sheraton Valley Electric Coop. ..... Albia Light and Railway Co. -- Unknown

PacificCorp .................... Utah Power & Light -- 10.3

1990

Central Vermont Public Service .... Allied Power & Light -- 0.5

Eastern Utilities ................ a Newport Electric Corp. -- 1.2

1991

UtiliCorp United ................. Centel Corporation -- 3.1

Kentucky Utilities Co. ............ Old Dominion Power Co. -- 1.7

1992

Connecticut Light and Power Co. . . . Fletcher Electric Light Co. -- 6.2

Iowa Public Service Co. .......... Iowa Power Co. MidWest Power 2.6 b

Kansas Power and Light Co. ...... Kansas Gas & Electric Western Resources 5.2 b

Indiana Michigan Power Co. ....... Michigan Power Co. -- 4.3

Unitil Corp. .................... a Fitchburg Gas & Electric Co. -- 0.2

NorthEast Utilities ............... a Public Service of New Hampshire -- 10.6

 See notes at end of table.
Table 8. Mergers and Acquisitions of Investor-Owned Utilities, 1986-1995 (Continued)

Merger Partner or Merger Partner or Name of Combined Assets

Acquiring Utility Utility Being Acquired New Company

1994

(Billion Dollars)

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 91

1993

Citizens Utilities Co. .............. Franklin ElectricLight Co. -- 3.4

IES Utilities Inc. ................. Iowa Electric Light and Power Co. IES Industries 1.8 b

Iowa Southern Utilities Co.

Texas Utilities .................. b Southwestern Electric Service Co. -- 20.9

Entergy Corp. .................. a Gulf State Utilities -- 22.6

1994

PSI Resources .................. Cincinnati Gas & Electric CINergy Corporation 8.1 b

1995

City of Groton, CT ............... Bozrah Light and Power -- Unknown

Delmarva Power and Light ........ Conowingo Power Co. -- 2.7

MidWest Power Systems ......... Iowa-Illinois Gas and Electric MidAmerican Energy Co. 4.4

Pending Mergersc

UtiliCorp United ................. Kansas City Power & Light Maxim Energies 5.9

WPL Holding .................. b IES Industries(b) Interstate Energy Corp. 4.3

Interstate Power Co.

Puget Sound Power & Light ....... Washington Energy Co. Puget Sound Energy 4.5

Baltimore Gas & Electric ......... b Potomac Electric Power Constellation Energy Corp. 13.4

PS of Colorado ................. b Southwestern PS New Century Energies 6.0

Ohio Edison Company ........... Centerior Energy Corporation FirstEnergy Corporation 19.5

Atlantic Energy, Inc. ............. Delmarva Power and Light Company Unknown 5.1

Union Electric Company .......... CIPSCO, Inc. Ameren Corporation 8.4

Northern States Power Company . . . Wisconsin Energy Corporation Primergy Corporation 10.4

New England Electric System ..... a Nantucket Electric --

d

Holding Company Registered under the Public Utility Holding Company Act of 1935. a

Holding Company exempt from the Public Utility Holding Company Act of 1935. MidAmerican Energy requested permission to b

reorganize into a holding company. 

The status of these mergers is unknown. As of April 1996, Primergy Corp. and New Century Energies have filed with the SEC for c

holding company status. MidAmerican Energy Co. requested FERC's approval to reorganize into a holding company.

Combined assets unknown. New England Electric System’s net utility plant assets are $3.7 billion. Nantucket is a small company d

serving about 9,000 customers.

 -- = No new company was established as a result of this merger.

Note: This table does not include acquisitions of other energy companies (i.e., natural gas or power marketers) by investor-owned

electric utilities.

Sources: Energy Information Administration, Financial Statistics of Major U.S. Investor-Owned Electric Utilities 1995, DOE/EIA0437(95/1) (Washington DC, December 1996); Public Power Annual Statistical Issue, Getting Big (January-February 1996), p. 10;

M. Frankena, “Electric Utility Mergers: Trends & Antitrust Update,” paper presented at the Institute of Public Utilities Annual Conference

(December 12, 1995); U.S. Securities and Exchange Commission, Financial and Corporate Report: Holding Companies Registered

Under the Public Utility Holding Company Act of 1935 as of October 1, 1995 (Washington, DC); U.S. Securities and Exchange

Commission, Financial and Corporate Report: Holding Companies Exempt from thePublic Utility Holding Company Act of 1935 as

of August 1, 1995 (Washington, DC); Edison Electric Institute, Catalogue of Investor-Owned Electric Utilities, 35th Edition (1995); and

various articles in trade journals and newspapers.
1987 1988 1989 1990 1991 1992 1993 1994

0

10

20

30

40

50

1994 Dollars per Megawatthour

Operations and Maintenance Salaries and Wages

Before Merger After Merger

1987 1988 1989 1990 1991 1992 1993 1994

0

10

20

30

40

50

1994 Dollars per Megawatthour

Operations and Maintenance Salaries and Wages

Before 

Merger

After Merger

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

 J. Wilson, “Merger Policy Guidelines for the Electric Power Industry,” The Electricity Journal (January/February 1996), p. 15. 214

 “Horizontal Merger Guidelines of 1992,” Department of Justice and the Federal Trade Commission. 215

Figure 19. Comparison of Costs Before and After

Merger of Iowa Power and Iowa Public 

Service

Note: Companies merged in 1992.The new name is Midwest

Power.

Source: Energy Information Administration, Financial

Statistics of Major U.S. Investor-Owned Utilities 1994, DOE/EIA0437(94/1) (Washington, DC, December 1995), and previous

issues.

Figure 20. Comparison of Costs Before and After

Merger of Kansas P&L and Kansas G&E

Note: Companies merged in 1992. Kansas P&L changed its

name to Western Resources.

 Source: Energy Information Administration, Financial

Statistics of Major U.S. Investor-Owned Utilities 1994, DOE/EIA0437(94/1) (Washington, DC, December 1995), and previous

issues.

about 13 percent. For the short term, this merger did not open access to the transmission lines, some analysts

produce any costs savings. believe that the owner of the lines can affect the relative

In comparison, the merger of Kansas Power & Light and increase the strategic position of the company in dealing

Kansas Gas & Electric had different results. In the 2 years with competitors.

following the merger, electricity sales for the merged

companies increased by 11 percent, while total O&M This issue and others related to mergers of IOUs are being

expenses remained approximately the same. The result discussed throughout the industry, and FERC is

was a decrease of $3.00 per MWh, or 11 percent, in real examining its criteria and policies for evaluating mergers

O&M costs over the 2 years following the merger (Figure in light of the changing industry. Many analysts have

20). More information is needed to conclude that the suggested that the merger guidelines used by the

merger caused the reduction in costs, but it probably Department of Justice (DOJ) and the Federal Trade Comhelped, which is an encouraging sign for advocates of mission (FTC) should be used by the FERC to evaluate the

utility mergers. affects of mergers on competition in the industry. These

Cost reduction is not the only reason for companies to geographic markets be defined, and then the conmerge. A merger of two vertically integrated utilities may centration within those markets be measured to determine

result in the consolidation of transmission networks, the proposed merger’s affect on competition. DOJ and

which enables one firm to control the facilities over which FTC evaluate competition using the Hirfindahlregional power supplies must flow. For example, Union Hirschman Index (HHI), a statistical technique that

Electric’s acquisition of Central Illinois Public Service will quantifies concentration of market shares in a given

result in ownership and control by one company of inter- industry. The HHI reflects the idea that possession of

connections with 28 other utility systems from southwest large shares of concentrated markets creates opportunities

Oklahoma to Chicago and eastward to the Tennessee for price leadership and for unilateral reductions in

Valley Authority and Ohio. Even with mandated output that boost prices above competitive levels.

success of rival generators and that ownership will

214

215

guidelines recommend that first the relevant product and
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 93

 Edison Electric Institute, Nonutility Business Activities of Investor-Owned Utilities (Washington, DC, 1994). 216

 Analysis of the changes in nonutility assets would be a better indication of diversification; however, a time series showing nonutility assets is not 217

available.

Investor-Owned Utility Diversification

Activities

Diversification is another business strategy that electric

utilities are using to remain viable. Investments in

nonutility businesses have been a feature of the electric

utility industry for decades. There have been four phases

of utility diversification over the past 20 years. Vertical 216

integration, primarily into mining and oil and gas exploration and development were the initial diversification

areas. Some of these were justified by the need for guaranteed fuel supplies and prices for power plants. The next

phase was acquisition of entities engaged in activities

outside of the core business. This kind of diversification

was practiced by most major industry segments. The results were mixed—some were successful while others

failed. The late 1980s saw a retrenching of the utility industry, with a leveling off in the number of new ventures.

More recently, with changing regulatory constraints and

increased competition, electric utilities are investing more

aggressively in nonutility businesses. The increase in

ownership of nonutility subsidiaries by electric utilities in

the past few years has been significant. From 1992

through 1994, registered electric utility holding companies

increased their ownership of nonutility businesses from 95

companies to 160 companies, an increase of almost 70 Other areas of opportunity have arisen recently for electric

percent in 3 years (Table 9). Exempt holding companies utilities. The 1996 Telecommunications Act allows the

show a similar pattern. In 1992, 72 exempt electric

holding companies owned 1,661 nonutility subsidiaries.

By 1994, exempt holding companies owned 1,954 nonutility businesses.217

Some of the largest companies in the electric power

industry are expanding their investments to energy

service companies, to cogeneration and independent

power production, to oil and gas exploration,

development, and production, and to foreign utility

ventures. Since about 1990, much of the growth in

diversification has come from international ventures.

Numerous utilities are taking advantage of worldwide

trends in privatization and restructuring to enter foreign

electric utility markets. The Energy Policy Act of 1992

(EPACT) provided a boost to international investments by

lifting some of the restrictions imposed by PUHCA. In

particular, it allowed holding companies to purchase

interests in foreign utility companies (FUCOs). It also

lifted restrictions on holding companies’ purchases of

cogeneration facilities and exempt wholesale generators

(EWGs). Many companies are taking advantage of these

opportunities. By the end of 1994, electric utility holding

companies had invested over $5 billion in EWGs and

FUCOs, representing slightly more than 1 percent of their

assets (Table 10).

Table 9. Number of Nonutility Subsidiary Companies Owned by Electric Utility Holding Companies,

1986-1994

Year

Registered Electric Exempt Electric Utility

Utility Holding Companies Holding Companies

Number of Number of Number of Number of

Electric Utilities Nonutility Subsidiaries Electric Utilities Nonutility Subsidiaries

1986 . . . . . . . . . . . . . . 10 47 52 515

1987 . . . . . . . . . . . . . . 10 51 -- --

1988 . . . . . . . . . . . . . . 10 46 69 1,014

1989 . . . . . . . . . . . . . . 10 70 -- --

1990 . . . . . . . . . . . . . . 10 64 71 1,630

1991 . . . . . . . . . . . . . . 10 67 -- --

1992 . . . . . . . . . . . . . . 10 95 72 1,661

1993 . . . . . . . . . . . . . . 11 116 -- --

1994 . . . . . . . . . . . . . . 12 160 69 1,954

 -- =Not available.

 Sources: U.S. Securities and Exchange Commission, Financial and Corporate Report, Holding Companies Registered Under the

Public Utility Holding Company Act (PUHCA) of 1935 as of October 1, 1995, and Holding Companies Exempt From the PUHCA as

of August 1, 1995 (Washington, DC).
94 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 “C&SW and Entergy Affiliates Win ‘ETC’ Status Under Telecommunications Act,” Electric Utility Week (April 22, 1996), p. 2. 218

Table 10. Investments in Exempt Wholesale Generators and Foreign Utilities in 1994

No. of Assets

Companies

Consolidated 

(million dollars) Million Dollars Percent

Investments in EWGs & FUCOs

Exempt Electric Utility Holding Companies ......... 69 288,603 3,785 1.3

Registered Electric Utility Holding Companies ....... 12 117,210 1,702 1.5

 EWGs = Exempt Wholesale Generators.

 FUCOs = Foreign Utility Companies.

 Sources: U.S. Securities and Exchange Commission, Financial and Corporate Report, Holding Companies Registered Under the

Public Utility Holding Company Act (PUHCA) of 1935 as of October 1, 1995, and Holding Companies Exempt From the PUHCA as

of August 1, 1995 (Washington, DC).

Federal Communications Commission (FCC) to approve ficant savings and other benefits from this acquisition.

telecommunications ventures owned by utility holding Houston Industries will acquire NorAm Energy Corcompanies after a 60-day review. Previously, such invest- poration, a gas distribution, gas pipeline, and marketing

ments were restricted by PUHCA, and applications were company. The company claims, and industry observers

subject to lengthy review by the Securities and Exchange agree, that this acquisition will give the company

Commission. The Entergy Corporation became the first additional marketing skills and customer access to help it

electric utility to receive an “exempt telecommunications thrive in a deregulated environment. These are a few

company” (ETC) designation from the FCC under the examples of electric utilities expanding into the natural

Telecommunications Act. Entergy Technology Company, gas business. Other companies are doing or at least

a subsidiary of the Entergy Corporation, will sell excess thinking about doing the same. Mergers of electric

capacity from its network to long-haul telephone utilities and gas companies are not new; there are

companies. Units of the Southern Company, Northeast numerous integrated gas and electricity utilities in

Utilities, and Allegheny Power have formally filed for existence today. On the other hand, competitive pressures

ETC status and are awaiting rulings. On the down side, may make mergers more attractive to utilities that have 218

investment in the telecommunications business may be not, as yet, expanded into other energy fields.

risky for electric utilities. They have little experience in

the field, as compared to phone companies, and they will

have to build the business from scratch. In the new

competitive environment, however, some IOUs see

diversification into a growing field like telecommunications as an opportunity to grow. On the other hand,

diversification into nonutility businesses does not guarantee that the company will prosper. There are risks involved, and diversification may distract attention from the

main activities of the company. Some utilities have given

up on nonutility business ventures and have decided to

invest in other utility and energy-related businesses.

Finally, the term “Btu supplier” may be only a buzz word,

but it also may signify a serious movement by electric

utilities to enter the natural gas business. For example,

Texas Utilities (TU) will acquire the gas distribution, gas

pipeline, and independent power subsidiaries of Enserch

Corporation. The gas distribution unit TU is acquiring,

Lone Star Gas, is the largest in Texas, serving over 1.3

million customers, including many of the customers

served by TU’s two electric units. TU officials claim signiCorporate Reorganization Activities

Many IOUs have reorganized their corporate structures or

plan to reorganize them in the near future. Reorganization

of the corporate structure can take many forms, such as

creating new divisions within the company to focus on

important functions, combining resources or functions to

improve efficiency, or creating a subsidiary company to

focus on new business opportunities. Although FERC

Order 888 does not require changes in corporate structures, many are choosing to reorganize, perhaps in part to

prepare for FERC’s open transmission access requirements

and for a different regulatory environment. For example,

Pacific Gas & Electric (PG&E) has established a new

generation business unit that will operate all of the

generating plants owned by the utility in its Northern and

Central California service territory. It also formed a

separate transmission business unit to operate its highvoltage transmission system throughout the service territory. With this separation of functions, PG&E believes

that they are in a better position to respond competitively.
50.6

19.9

14.6 11.7

3.3

Operations

& Maintenance

Expense

Operating

Income

Fuel

Expense

Depreciation 

& Amortization

Taxes 

Revenue Allocation Category

0

10

20

30

40

50

60

Percent of Revenue

$23 Billion in Revenues

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 95

 Costs are for over 200 major publicly owned generator electric utilities reported in Energy Information Administration, Financial Statistics of Major 219

U.S. Publicly Owned Electric Utilities 1994, DOE/EIA-0437(94/2) (Washington, DC, December 1995).

Figure 21. Allocation of Revenue Dollars from

Electric Operations for Publicly Owned

Generator Utilities, 1994

 Note: Totals may not equal sum of components due to

independent rounding.

 Source: Energy Information Administration, Financial

Statistics of Major U.S. Publicly Owned Electric Utilities 1994,

DOE/EIA-0437(94/2) (Washington, DC, December 1995).

Another reason for corporate reorganization is to give

more attention to customer needs. To remain competitive

in today’s business environment and to endure in the

future, firms must address and achieve customer satisfaction. More competition requires utilities to provide

new products and better service and, in general, to give

more attention to customer needs. Many companies are

creating units within their organizations to focus on

improving customer relations and services.

In general, corporate reorganization, in one form or

another, is happening throughout the industry, and it is

expected to continue as IOUs look to become more

efficient and more flexible in a restructured industry.

Publicly Owned Utilities 

and Cooperatives

Publicly owned utilities (municipal, Federal, State, and

other government owned utilities) and rural electric

cooperatives make up a much smaller share of electric

sales than the vertically integrated IOUs. In 1994, publicly owned utilities and cooperatives accounted for a

combined 14 percent of retail electricity sales, compared

with 76 percent for IOUs. Although relatively small in

comparison to IOUs, publicly owned utilities and cooperatives will be affected by restructuring of wholesale

markets. Publicly owned utilities and cooperatives with

generation facilities (most of these utilities do not have

generation or transmission facilities--they are distribution

utilities only) may want to expand electricity sales into

other markets, and they will need access to transmission

lines at a competitive price. On the other hand, they may

face competition from other utilities or power marketers

seeking to sell electricity in their markets. With open

transmission access, publicly owned utilities that only

distribute power will have more opportunity to purchase

lower priced electricity from companies other than their

normal suppliers. Thus, they have a stake in the outcome

of deregulation. 

Publicly Owned Utility Activities

In 1994, major publicly owned utilities with generating

capacity, excluding Federal utilities, had $23 billion in

revenues, most of which went to pay for O&M expenses

(Figure 21). About 15 percent of their revenues went for

fuel purchases and less than 4 percent for taxes. (Publicly

owned utilities are exempt from most taxes.) In 1994,

generator utilities’ O&M expenses were $15 billion, of

which 39 percent went toward power production and 37

percent toward power purchases (Figure 22). Publicly

owned utilities rely on power purchases to a greater

extent than do IOUs to meet their requirements for power,

and federally owned Power Marketing Administrations

(PMAs) are a source of relatively low-cost power for many

of them. By law, PMAs are required to give priority in

power sales to “preference customers,” which include

public utility districts, municipalities, and customerowned cooperatives. While publicly owned utilities may

have some competitive advantage over IOUs as a result of

tax exemptions and access to low-cost power from PMAs,

they still must keep their costs down to stay competitive

in the restructured industry. From 1989 through 1994

their average O&M costs were lower than those of IOUs,

and if this trend continues, they will be in a relatively

favorable competitive position. Real O&M costs for

publicly owned utilities went from 3.5 cents per kWh in

1989 to about 3.3 cents per kWh in 1994 (Figure 23), as 219

lower fuel costs helped reduce O&M expenses.

Unlike IOUs, publicly owned utilities in general have not

joined the merger trend. In 1986 there were 1,991 nonFederal publicly owned utilities, which accounted for
38.9 37.2

13.8

10.1

Power 

Production

Power 

Purchase

Administration

and General

Transmission

and Distribution

Expense Type

0

10

20

30

40

50

Percent of O&M Expenses

$15 Billion in O&M Expenses

1989 1990 1991 1992 1993 1994

2.2

2.4

2.6

2.8

3

3.2

3.4

3.6

3.8

4

1994 Cents per Kilowatthour

Operation and Maintenance

with Fuel

Operation and Maintenance

without Fuel

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

 “IOU Mergers Truly in Vogue, But Munis Seem Unaffected,” Inside F.E.R.C. (August 1995). 220

Figure 22. Allocation of Electric Operation and

Maintenance Expenses for Publicly

Owned Generator Utilities, 1994

Figure 23. Operation and Maintenance Expenses

for Publicly Owned Electric Utilities, 

1989-1994

 Source: Energy Information Administration, Financial

Statistics of Major U.S. Publicly Owned Electric Utilities 1994,

DOE/EIA-0437(94/2) (Washington, DC, December 1995). Note: Includes only Public Utilities with generators.

Source: Energy Information Administration, Financial

Statistics of Major U.S. Publicly Owned Electric Utilities 1994,

DOE/EIA-0437(94/2) (Washington, DC, December 1995).

about 15 percent of total industry sales. In 1994 there

were 2,005 non-Federal, publicly owned utilities,

accounting for 14 percent of total industry sales. The

incentives for publicly owned utilities to merge are not as

great as those for IOUs. Most publicly owned utilities do Also, it is believed by some publicly owned utilities that

not have generation facilities, and gains in production even a fully effective comparable transmission tariff will

efficiency from a merger are not an issue. In situations not eliminate excess market power in generation. With

where efficiency is an issue, publicly owned utilities the increase in merger activity of IOUs, publicly owned

traditionally have formed alliances or “mutual aid” utilities believe that an appropriate merger policy is

programs, such as joint equipment-purchasing programs. essential to prevent unnecessary consolidation of IOU

They also have gone the route of joint-action programs, generation capacity.

which capture some of the same efficiencies as a merger.220

In general, publicly owned utilities are more likely to

compete by controlling internal costs and sharing services.

Many publicly owned utilities are concerned that mergers

of IOUs in their regions will create excess market power.

Some of them have publicly voiced their objections to the

FERC. For example, public utility officials in Illinois and

Missouri have asked the FERC to require Union Electric

and Central Illinois Public Service to form an independent

system operator (ISO) to mitigate the market power that

the utilities would have if they were allowed to merge.

They claim that comparable transmission service cannot

be achieved if the merging utilities are free to administer

their tariffs. In another case, affected publicly owned

utilities and cooperatives told FERC that the proposed

three-utility Interstate Energy merger proposal is anticompetitive and should be either rejected or set for hearing.

The publicly owned utilities and cooperatives claimed

that the merger plans failed to include plans for an ISO.

Rural Electric Cooperative Activities

Rural electric cooperatives (RECs), which provide electricity to sparsely populated areas, are an important

segment of the industry. Currently, 939 RECs in 46 States

are serving approximately 30 million customers. Most of

them distribute electricity only, and are owned by the

customers they serve. Distribution cooperatives engage

primarily in local distribution and sale of electricity,

depending on the transmission lines of neighboring

utilities—often IOUs—to obtain power. Cooperatives

sometimes have large customers within easy reach of an

IOU’s transmission facilities, and they are concerned

about retaining such customers in a more competitive

environment. 

Recognizing the problems inherent in relying on outside

sources for power supply, many distribution cooperatives

have joined together to obtain their own generation and

transmission facilitites, forming umbrella “generation and
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 97

 T.D. Kilgore, “Congressional Testimony House Commerce Energy and Power Electricity Regulation,” Federal Document Clearing House, Inc. (May 221

15, 1996).

Citizens Power & Light Corp., 48 Federal Energy Regulatory Commission (FERC) 61,210 (August 8, 1989). 222

 Energy Information Administration, Electric Power Annual, Volume II, DOE/EIA-0348(94/2) (Washington, DC, November 1995). 223

 For further information regarding the provisions contained in EPACT, see Chapter 4 of this report. 224

transmission” (G&T) cooperatives to own and operate the of all G&Ts, is an example of a company improving its

facilities. There are now 60 G&T cooperatives, and over internal operations and procedures to remain competitive.

720 distribution cooperatives are members-owners of G&T

cooperatives. Each member cooperative generally has a Some cooperatives are looking to mergers to stay

contract to purchase all of its power requirements from competitive, although not to the same extent as IOUs.

the G&T. Under this structure, the G&T and its distri- Two Kansas cooperatives plan to combine their companies

bution cooperatives are bound to each other by both in January 1997, with expected savings of $2.8 million

ownership and contract. over 10 years. Two North Dakota cooperatives have

It is difficult to generalize about the reactions of G&Ts to in administrative and operation costs over 10 years. In the

restructuring. Some are very competitive power supply near future, more cooperatives may recognize the improviders for their cooperative members. Others have portance of economies of scale and shared resources in the

invested in high-cost generation facilities (in many cases, new competitive era. Where significant costs savings can

the same high-cost units for which IOUs are now seeking be realized, it is reasonable to expect that more mergers

recovery of stranded costs) and are burdened with high- will be announced.

cost power, making them uncompetitive. Cajun Electric

Power Cooperative, one of the larger G&Ts, is an example

of a cooperative that is not competitive in today’s industry. Cajun invested in a minority share of the River

Bend Nuclear Plant built by Gulf States Utilities Company. The project had huge cost overruns, which Cajun

could not pass through in customer rates, causing the

cooperative to file for bankruptcy. Vermont Electric

Cooperative (VEC) is another example of a company that

is not competitive in today’s electricity market. Similar to

Cajun’s situation, VEC’s investments in nuclear power

were declared imprudent by the Public Service Board

(PSB) of Vermont, and recovery of the costs was

disallowed. The PSB also rejected a debt payment plan

for $115 million in defaulted loans, reasoning that because

of increasing competition, the plan would not be economically viable over the long term.

In contrast, Oglethorpe Power Corporation, the largest

power supply cooperative in the United States, has taken

many steps to stay competitive. Through a cost man- 221

agement program, Oglethorpe has reduced labor costs by

32 percent over recent years and has avoided cost increases despite placing over $900 million of electrical

plant in service. In January 1996, Oglethorpe signed a 4-

month agreement with Enron Power Marketing, Inc., to

provide the full power needs of its 39 member systems.

According to Oglethorpe, this short-term deal saved the

company several million dollars. Oglethorpe has since extended the power purchase agreement with Enron for 4

months and is working to finalize a long-term arrangement with one or more power marketers that, Oglethorpe

believes, will produce cost savings for its member systems. Oglethorpe, although not necessarily representative

agreed to a merger that will save an estimated $9.4 million

Power Marketers

Power marketers are a relatively new type of firm in the

electric power industry. They are different from traditional electric utilities. A power marketer buys electric

energy and transmission and other services from traditional utilities, or other suppliers, and then resells these

products. The concept of a power marketer first appeared

in the mid-1980s. In October 1985, Citizens Energy filed

a petition with the FERC seeking approval to purchase

and resell electricity. This company was the first to file

such a petition. In July 1987, the second petition to buy

and resell electrical power was filed with the FERC by

Howell Gas Management. It was not until August 1989,

however, that the FERC approved a petition granting the

right to buy and resell electric power to Citizens Power

and Light. This order was particularly significant 222

because the FERC recognized the existence of a new type

of company in the wholesale marketplace and accepted

the market-based rate schedules proposed by Citizens.

That approval proved to be the foundation for subsequent

applications for power marketing status. 

Growth in the wholesale power market—estimated to be

around 1,343 billion kWh in 1994 —has spurred the 223

increase in power marketing companies. EPACT and 224

FERC’s movement toward increased competition in the

wholesale market by allowing market-based rates were

also major factors in the increase in power marketers.

Since the first approvals for power marketing status were

granted, the number of companies obtaining approval

has increased substantially. From a total of 9 in 1992, the
98 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 Edison Electric Institute, Power Marketers Yearbook 1995 (Washington, DC, 1995); and Utility Data Institute, Who’s Who in Power Marketing (May 225

1996).

number had grown to 180 by the end of December 1995. Exchange (CPEX) has started a computerized electricity

Most of the companies are gas marketers, who see power trading market. According to CPEX, as of March 1996, 30

generation as a potentially lucrative market. Others types companies in 28 States across the United States were using

of companies getting into the power marketing business the electronic exchange, and CPEX expects the market

include brokers and financial firms, utility affiliates, to grow as the industry becomes more accustomed to

independent entrepreneurs, commodity traders and electronic trading. The development of market centers for

manufactures, and independent power producers. electricity trading is indicative of a change in fundamental

Presently, only a relatively small number of power structuring and increased competition in the electric

marketers are active in the market, but the number of industry.

active companies is growing. In 1994, 9 firms sold 7.2

million MWh. In 1995, 40 power marketers sold 26.6 Public information on prices is necessary for a spot market

million MWh of electricity. Three companies—Enron to function properly. That is, to make informed purPower Marketing, Lewis Dreyfus, and Electric Clearing- chasing decisions, potential electricity buyers need price

house—accounted for 57 percent of the sales. information on recent transactions. In June 225 1995, Dow

In summary, the growth of power marketers signals the markets by compiling peak and off-peak electricity price

potential for a fundamental change in the wholesale elec- indices for non-firm power at the COB. Later, DJ began

tricity business. Since the late 1980s the number of com- compiling firm and non-firm price indices on transactions

panies approved for power marketing has gone from a at Palo Verde, and now both the COB and Palo Verde

few to 180. Presently, only about 10 companies are active indices are published daily in the Wall Street Journal. DJ

in the business of buying and reselling power. It is expec- also compiles price indices, which are available by

ted that, as access to transmission lines increases in a com- subscription, for Mid-Columbia and for the North

petitive environment, more companies will become active American Reliability Council regions MAIN and ECAR.

in the wholesale electric power business as power mar- CPEX has also recently begun publishing a price index in

keters. the Energy Daily for transactions occurring during peak

Spot Markets 

and New Trading Mechanisms

Electricity is becoming a commodity like natural gas, One of the most interesting developments in the industry

petroleum products (e.g., crude oil, heating oil, gasoline), is the electricity futures contract. On March 29, 1996, The

and other energy products. Electricity at wholesale value New York Mercantile Exchange (NYMEX) began selling

is now sold at market centers at market-based rates, and electricity futures contracts for the COB and Palo Verde

wholesale electricity prices are published daily. Two new markets. NYMEX indicated that the futures contract was

electricity futures contracts have been introduced, which designed to service a growing wholesale trade at these

can help electricity buyers and sellers manage business market centers. The contract, which is standard for both

risk. These events are relatively new, and they mark the COB and Palo Verde, covers 736 MWh delivered over a

beginning of a new era in the electric power industry. month (Table 11). July settlement prices at COB for

Wholesale electricity spot markets are now operating at of $12.54 per MWh. The July settlement prices at Palo

several sites in the western United States. The Pacific Verde were slightly higher. On April 26, 1996, NYMEX

Northwest/Pacific Southwest AC Intertie transmission introduced electricity options contracts at the COB and

facilities between the California-Oregon Border (referred Palo Verde. An option on a future gives the purchasing

to as COB), and the Palo Verde Nuclear Power Plant high- party the right, but not the obligation, to buy (in the case

voltage switchyard in Arizona are two transfer points of a call option) or sell (in the case of a put option) the

with spot markets. Wholesale electricity is also traded at underlying futures. It can be thought of as a form of

five delivery points spanning approximately a 100-mile insurance against high or low futures prices. The buyer of

area in Washington State (referred to collectively as Mid- the option pays the option writer an up-front premium for

Columbia). In Atlanta, Georgia, Continental Power this insurance. 

business procedures brought about, in part, by reJones & Company (DJ) met that need for the western

hours on the computerized exchange. The DJ and CPEX

price indices should help sustain the growth in trading at

these market centers, and as the industry becomes more

competitive, spot markets and price indices may develop

for other areas of the country.

trading in May 1996 ranged from a low of $11.35 to a high
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 99

 In Order 888, FERC outlined 12 principles an ISO should follow in its management of a transmission network. 226

Table 11. NYMEX Futures Contract

Contract Unit:

736 megawatt hours (MWh) delivered over a month.

Delivery Rate: 

2 megawatt (MW) throughout every hour of the delivery

period (can be amended).

Delivery Period:

Sixteen on-peak hours from 0700 prevailing time to 2200

(can be amended by mutal consent).

Termination of Trading:

Trading in the delivery month shall cease on the third

business day prior to the first day of the delivery month.

Prices and Price Fluctuations:

Prices shall be quoted in dollars per MWh. The minimum

price fluctuation will be 1 cent per MWh. The maximum

permissible price will be $3.00 per MWh above or below

the preceding day’s settlement price. Expanded limits will

apply when the contract settles at the limit. 

Scheduling:

Buyer and seller must follow Western Systems

Coordinating Council scheduling practices. 

It is expected that power marketers will initially be the

most likely users of the electricity futures. A power

marketer entering into a contract to sell power at a

predetermined price runs the risk that the price it must

pay for electricity will increase before the power is

delivered. The power marketer can hedge its risk by

buying electricity futures that match the quantity and

timing of the original power contract (see inset below).

Under traditional cost-plus regulation, IOUs may not find

these risk-management tools very useful. However, in

order to participate in the growing wholesale markets, it

is expected that many IOUs will submit applications

seeking FERC approval to sell wholesale power at marketbased rates. FERC Order 888 discusses this issue, and it

sets the framework for transmission-owning utilities and

their affiliates to participate in these markets. Indeed,

FERC’s stated goal is to develop more competitive bulk

power markets.

Independent System Operators

ISOs are a new concept in the electric utility industry.

Their purpose will be to manage the transmission network

in such a way as to allow open and equal access to all

electricity buyers and sellers. The FERC does not require

utilities to have an ISO in order to ensure open and equal

access to the transmission network, but by providing

standards for approval, FERC encourages companies and

regional power pools to explore the concept. 226

Questions arise as to what exactly an ISO will do to

manage the transmission network, and how decisions will

be made. The answers to these questions are being

worked out by State commissions and utilities considering

this option. It is clear, however, that the ISO will be

responsible for reliability and security of the transmission

system. The ISO will probably oversee all maintenance,

even if the transmission owners provide day-to-day

maintenance. The FERC guidelines, noted above, provide

some light on other functions of an ISO. They include

congestion management, administering transmission and

ancillary pricing, making transmission information

publicly available, and other activities. It is expected that

these functions will not be performed by all ISOs; there

will be differences from region to region. 

Many proposals to form ISOs have been reported recently

in the trade journals. Some applications to form ISOs

have been filed with FERC. The California Public Utility

Commission’s proposal to transfer operational control (but

not ownership) of certain transmission facilities to an ISO

is perhaps the most visible and publicized ISO plan.

Proposals to start ISOs are also being discussed in New

York, Wisconsin, Massachusetts, Texas, and numerous

other States. Thus, interest in the ISO concept appears to

be spreading across the country, and it is expected that

many of them will be formed over the next several years.
Short Position Payoff

LOSS

PROFIT

Short Sale Price

FUTURES

PRICE

FUTURES

PRICE

CHANGE (-) CHANGE (+)

Long Position Payoff

LOSS

PROFIT

Purchase 

Price

FUTURES

PRICE

FUTURES

PRICE

CHANGE (-) CHANGE (+)

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

 Futures Positions

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

Figure 24. Payoff Diagram for Long and Short 

Background Information on Futures Contracts

Futures contracts are a standardized form of forward contracting that has been practiced for centuries. However, they differ from

forward contracts in that they are standardized and traded on an organized exchange, rather than being the result of negotiations

between two parties. These contracts have several key features:

 The buyer of a futures contract is said to be in a “ long” position, and agrees to receive delivery of the commodity.

 The seller of a futures contract is said to be in a “short” position, and agrees to make delivery of the commodity.

 The contracts are traded on exchanges either by open outcry in specified trading areas or electronically via a computerized

network.

 Futures contracts can be terminated by an offsetting transaction executed at any time prior to the contract’s expiration. Most

futures contracts are terminated by offsetting transactions.

 The same or similar futures contracts can be traded on more than one exchange in the United States or elsewhere.

If you buy a futures contract (go long) and the price goes up, you profit by the amount of the price increase times the contract size;

if you buy and the price goes down, you lose an amount equal to the price decrease times the contract size (Figure 24). If you sell

a futures contract (go short) and the price goes down, you profit by the amount of the price decrease times the contract size; if you

sell and the price goes up, you lose an amount equal to the price increase times the contract size (Figure 24).

Options are another type of financial instrument. Option contracts are usually introduced on a commodity after the futures contract

is trading successfully. An option is the right, but not the obligation, to buy or sell a specified number of underlying futures contracts

or a specified number of commodity, currency, index, or financial instruments at a price agreed upon on or before a given future

date. Options on futures are traded on the same exchanges that trade the underlying futures contracts. They can be thought of

as a form of insurance against high or low prices. The buyer of the option pays the option writer an up-front premium for this

insurance. The major difference between futures and options centers on the obligations of the purchaser and the seller. A futures

contract obligates the seller to execute the contract, regardless of whether it is profitable or not. In contrast, a purchased option

is a limited-risk instrument because, as noted above, the option purchaser has the right, but not the obligation, to buy or sell the

underlying futures contract at the option’s strike price. At expiration, an option that is worthless will not be exercised, and the option

purchaser’s loss is limited to the premium paid to buy the option.
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 101

Background Information on Futures Contracts (Continued)

Futures markets have evolved and flourished because they serve useful purposes. The two main functions of futures

contracts are price discovery and risk transfer. Futures prices are determined through open and competitive bidding among a

large number of market participants. Because futures contracts are standardized and traded on a central exchange, prices

can be readily observed and compared. The future price of a commodity may be the best indicator of its expected spot price

in the future. Indeed, in a stable commodity market, the market price of a commodity must converge to the futures price by the

time the futures contract expires, otherwise anyone could engage in arbitrage. Arbitrage occurs when the price of an asset

traded on two or more markets is different. Profit is made by buying the asset at the low price in one market and selling it at a

higher price in another market. Risk transfer is the other main function of the futures market. Participants in the futures market

are generally classified as hedgers or speculators. Hedgers use futures contracts to offset and minimize the risks of price

fluctuations. Speculators, on the other hand, are willing to accept this risk in the hope of earning a profit. 

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

History of the U.S.

Electric Power Industry,

1882-1991
Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update 105

 The following is a historical sketch of the electric power industry from 1882 through 1991. The information for utilities from 1882 to 1984 is 227

excerpted from the Annual Outlook for U.S. Electric Power 1985. Utility and nonutility information from 1985 to 1991 is excerpted from The Changing

Structure of the U.S. Electric Power Industry 1970-1991.

 C. E. Neil, “Entering the Seventh Decade of Electric Power, Some Highlights in the History of Electrical Development,” reprinted from Edison Electric 228

Institute Bulletin (September 1942), p. 6.

 A.J. Foster, The Coming of the Electrical Age to the United States (New York, NY: Arno Press, 1979), pp. 120, 123, 181. 229

 Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970 (New York, NY), p. 24. 230

 C.E. Neil, “Entering the Seventh Decade of Electric Power,” from Edison Electric Institute Bulletin (September 1942), p. 6. 231

Appendix A

History of the U.S. Electric Power Industry, 1882-1991227

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.228

Initially the Pearl Street utility served 59 customers for

about 24 cents per kilowatthour. In the late 1880s, power 229

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 Era of Private Utilities: 1901-1932

stations dotted many U.S. cities; each was limited to a few

blocks' area because of transmission inefficiencies of direct From 1901 through 1932, growing economies of scale

current (dc). hastened growth and consolidation in the electric utility

The hydroelectric development of Niagara Falls by regulation. Larger, more efficient steam turbine-powered

George Westinghouse in 1896 inaugurated the practice of generators quickly replaced reciprocating steam engines;

placing generating stations far from consumption centers. average heat rates dropped from 92,500 Btu per

The Niagara plant transmitted massive amounts of power kilowatthour in 1902 to 20,700 Btu per kilowatthour by

to Buffalo, New York, over 20 miles away. With Niagara, 1932. As a direct consequence of those growing

Westinghouse convincingly demonstrated both the efficiencies, small private and municipal lighting and

general superiority of transmitting power with electricity railway or power companies either merged with,

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 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.230

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.

industry, as well as the beginnings of State and Federal

231
106 Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update

Encyclopedia Americana, International Edition, Vol. 22 (New York, NY: Americana Corporation, 1977), p. 769. 232

 Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970, p. 24. 233

 U.S. Bureau of the Census, Historical Statistics of the United States, Colonial Times to 1970, Bicentennial Edition, Part 2 (Washington, DC, 1975), 234

p. 827.

purchased electricity from, or were absorbed quickly by 94 percent. Electricity prices dropped, with nominal

ever-larger, more efficient private multiservice systems. residential electricity prices falling to 5.6 cents per

Systems and cities interconnected with high voltage kilowatthour in 1932, a level about one-third their price at

transmission lines. Private electric utility ownership also the beginning of the century. In 1907, only 8 percent of all

consolidated into large utility holding companies, each dwellings were using electricity; by 1932, this figure had

“holding” controlling interest in a number of electric risen to 67 percent. By 1932 considerably more than 80

utilities. At their peak in the late 1920s, the 16 largest percent of urban dwellings were electrified, while only 11

electric power holding companies controlled over 75 percent of farm dwellings had electrical service. This

percent of all U.S. generation. disparity between urban and rural service led to demands 232

The growth of utility service areas, first beyond city power.

boundaries and then across State lines, brought State

regulation of electric utilities in the early 1900s. 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 over 1 percent of

total generation. Private utilities provided the remaining

233

by farm interests for government help in obtaining electric 234

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
Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update 107

 U.S. Bureau of the Census, Historical Statistics of the United States, p. 827. 235

 Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970, pp. 2, 24. 236

 C.E. Neil, “Entering the Seventh Decade of Electric Power,” from Edison Electric Institute Bulletin (September 1942), p. 6. 237

 Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970, p. 24. 238

 Edison Electric Institute, EEI Pocketbook of Electric Utility Industry Statistics (New York, NY: 1983), p. 21. 239

 Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970, p. 24. 240

organizations providing electricity to rural areas and power grew steadily from 1932 to 1941, with generation

towns with populations under 2,500. REA-backed growth averaging over 8 percent a year, although capacity

cooperatives enjoyed Federal power preferences plus increased less than 2.5 percent per year.

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 1932.235

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.236

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. Improvements in transformers, 237

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

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 over 12.5 percent of

U.S. generation. Total U.S. generation grew at an annual 238

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 kilowatthour and residential 239

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 Corps of Engineers' electric power sales

and extended public preference to all Corps power. The

Southwestern Power Administration (SPA) 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. In settling the Hope Natural 240

Gas case (Federal Power Commission vs. Hope Natural
108 Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update

 U.S. Bureau of the Census, Historical Statistics of the United States, pp. 827-828. 241

 Derived from Edison Electric Institute, EEI Pocketbook of Electric Utility Industry Statistics (1983), p. 21. 242

 Residential price declines for 1950 to 1960 are derived solely from Edison Electric Institute data. 243

 Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970, p. 24. 244

 Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970, p. 24. 245

Gas Company, 1944), the Supreme Court closed a Commercial nuclear power was introduced in the 1950s.

longstanding dispute by allowing either original or The Atomic Energy Act of 1954 (P.L. 83-703) allowed

replacement cost accounting in utility ratemaking, so long private development of commercial nuclear power, and

as just and reasonable rates result. the Price-Anderson Act (P.L. 85-256) reduced private

Following a brief decline at war's end in 1945, overall

demand for electricity continued to grow. From 1945

through 1950, generation growth averaged over 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. Growth was encouraged by continued 241

efficiency improvements; by 1950 heat rates had fallen

below 15,000 Btu per kilowatthour. Drops in nominal 242

residential electricity prices averaged 3 percent a year.

Utility Prosperity: 1951-1970

The era following the end of World War II through 1970

marks 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 mark 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.243

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, over 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 over 6.5 percent of total generation in 1950

to almost 8.5 percent in 1960.244

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. Demand grew nearly 7.5 percent a 245
Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update 109

 Energy Information Administration, Annual Energy Review 1984, DOE/EIA-0384(84) (Washington, DC, April 1985), p. 187. 246

 Energy Information Administration, U.S Commercial Nuclear Power Historical Perspective, Current Status, and Outlook, DOE/EIA-0315 247

(Washington, DC, March 1982), p. 10.

 Energy Information Administration, Annual Energy Review 1984, p. 171. 248

 Energy Information Administration, Thermal-Electric Plant Construction Cost and Annual Production Expenses—1979, DOE/EIA-0323(79) 249

(Washington, DC, May 1982), p. 10.

 Energy Information Administration, “Fuel Choice in Steam Electric Generation: A Retrospective Analysis,” Volume 1, Overview, Draft Report, Table 250

2.

year, helped by annual declines of over 1.5 percent in

residential and commercial electricity prices.246

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.247

Generation by nuclear power rose to over 1 percent of the

U.S total by 1970.248

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 (SO ) emitted into the atmosphere. Tall 2

emission stacks were introduced to disperse SO . Further, 2

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 (EIS) 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. Finally a major Northeastern 249

power blackout in 1965 raised concerns about the

reliability of the huge interconnected, interdependent

power networks; response to the blackout included

formation of regional reliability councils, and the North

American Electric Reliability Council (NERC) 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.250

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 SO , causing increases in capital, 2

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.
110 Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update

 Energy Information Administration, U.S Commercial Nuclear Power (March 1982), p. 10. 251

 Energy Information Administration, 1983 Survey of Nuclear Power Plant Construction Costs, DOE/EIA-0439(83) (Washington, DC, December 252

1983), p. 8.

 Energy Information Administration, U.S. Commercial Nuclear Power (March 1982), p. 10. 253

 Energy Information Administration, Survey of Nuclear Power Plant Construction Costs 1984, DOE/EIA-0439(84) (Washington, DC, November 254

1984), p. 15.

 Energy Information Administration, Annual Energy Review 1984, pp. 179, 187. 255

Finally, conservation legislation effectively barred utilities As a result of higher costs, slackening electricity demand

from wider use of natural gas and petroleum. The Energy growth, and public concern, demand for nuclear power

Supply and Environmental Coordination Act of 1974 plants dropped quickly in the mid- and late-1970s. After

(ESECA, P.L. 93-319) allowed the Federal Government to 1974, new orders plummeted and cancellations accelerprohibit electric utilities from burning natural gas or pe- ated. No new reactor orders were placed after 1978. Moretroleum. The 1978 Powerplant and Industrial Fuel Use Act over, 63 units were canceled between 1975 and 1980.

(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.

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. Inflation and real 251

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 over $600 after

1976. Utilities building commercial nuclear facilities 252

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.

253

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 over $1,200 per kilowatt of

capacity in the early 1980s. High inflation ensured 254

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.255

However, other factors also slowed cost increases in the

early 1980s. Growth in Federal fuel use restrictions

slowed. The Omnibus Budget Reconciliation Act of 1981

(P.L. 97-35) reduced Federal authority to issue oil and

natural gas use prohibitions. Additional Clean Air Act

amendments were considered but not enacted. Despite the

accelerated decontrol of petroleum prices, worldwide oil

surpluses in the early 1980s resulted in lower utility oil

costs and provided some relief. Finally, while the

recession of 1982 undoubtedly hurt electricity sales, it

lowered the rate of overall inflation, resulting in lower

interest rates and lowered rates of increase in other

capital, operating, and maintenance costs.

Electricity generation increased in 1983 to a record high of

2,310 billion kilowatthours. Capacity, however, grew by
Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update 111

 Energy Information Administration, Annual Energy Review 1984, pp. 171, 179, 181, 187, and the U.S. Department of Commerce, Bureau of 256

Economic Analysis.

 Reprinted from The Changing Structure of the U.S. Electric Power Industry, 1970-1991, DOE/EIA-0562 (Washington, DC, March 1993), pp. vii-ix. 257

 Edison Electric Institute, 1991 Capacity and Generation of Non-Utility Sources of Energy (Washington, DC, November 1992), p. 21. 258

little more than 1 percent over 1982, the smallest increase capacity and produced about 9 percent of the total

since 1956. Industrial electricity use grew most rapidly electricity generated in the United States.

among end-use sectors, rebounding from its 1982 decline.

The average price of electricity increased by 2.6 percent, About one-half of 1991 nonutility capacity was located in

less than the rate of inflation. the West South Central Census Division, particularly in

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.

From 1980 through 1984, net electricity generation grew

an average of a mere 1.4 percent annually. Gross National

Product grew at twice that, yielding a GNP ratio of only

0.5. 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.256

Nonutility Growth: The Late 1980s paper, making wood and wood waste easily accessible to 257

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

258

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 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 are arising and include the effect of

the changing industry structure on the reliability of

electric power supply and on bulk (wholesale) power

trade. Also at issue is whether the Clean Air Act Amendments of 1990 will alter the course of nonutility growth.

The concern with the Clean Air Act Amendments of 1990

centers on whether nonutilities will 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),
112 Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update

the Amendments require virtually all suppliers of whole- obtain the allowances they need from utilities or from a

sale electric power to obtain emission allowances for any sale or auction administered by the Federal Government.

sulfur dioxide released into the atmosphere. Utilities have Allowances should be available to nonutilities, but there

been allocated most of these allowances. Nonutilities must have not yet been enough trades to resolve their price.
Appendix B

Historical Chronology

of Energy-Related 

Milestones, 1800-199
Appendix C

Statistical Tables

for the 

Electric Power Industry
Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update 127

Class of Ownership

 Investor-Owned .................................... 557.3

 Federal ........................................... 66.7

 Other Publicly Owned ............................... a 88.1

 Cooperative ....................................... 33.1

 Other ............................................ b 5.4

 Total ............................................ 750.5

 The Other Publicly Owned category includes utilities owned by States, municipalities, and a

other political subdivisions (i.e., districts or public agencies).

 Other is capacity that is operated by a utility for an owner that is not a utility. b

 Notes: •Nameplate capacity is used for comparison to nonutilities, instead of the more

commonly used net summer capability, because net summer capability is not collected for

nonutilities. •Sum of components may not equal total due to independent rounding.

 Source: Energy Information Administration, Inventory of Power Plants in the United States

1995, DOE/EIA-0095(95) (Washington, DC, December 1996), Table E3.

Table C1. Nameplate Capacity at Utilities by Class of Ownership, 1995

(Gigawatts)

Table C2. Nameplate Capacity at Nonutilities by Type of Facility and Major Industry Group, 1995

(Gigawatts)

Type of Facility Major Industry Groupa

 Cogenerator Qualifying Facility . . . . . . . . . . 42.3 Manufacturing

 Small Power Producer Chemical . . . . . . . . . . . . . . . . . . . . . . . . . 15.5

 Qualifying Facility . . . . . . . . . . . . . . . . . . . 9.7 Paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.9

 Exempt Wholesale Generator . . . . . . . . . . 2.4 Petroleum Refining . . . . . . . . . . . . . . . . . 6.4

 Two or more of the above . . . . . . . . . . . . . . 3.5 Other Manufacturing . . . . . . . . . . . . . . . . 13.7

 Electric, Gas, and Sanitary Services . . . . . . 14.9

 Cogenerator Non-Qualifying Facility . . . . . . 6.9 Mining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4

 Noncogenerator Non-Qualifying Facility . . . 5.5 Other Industries . . . . . . . . . . . . . . . . . . . . . . 4.4

 Total ............................. 70.3 Total ............................. 70.3

 The classification system used is the Standard Industrial Classification (SIC). a

 Notes: •Sum of components may not equal total due to independent rounding. •Nonutility data are for facilities of 1 megawatt

or more.

 Source: Energy Information Administration, Form EIA-867, “Annual Nonutility Power Producer Report,” (1995).

Appendix C

Statistical Tables for the Electric Power Industry
128 Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update

Nonutility

Prime Mover

 Fossil Steam (Fluidized Bed) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.4

 Fossil Steam (Other) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5

 Combustion Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6

 Hydraulic Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3

 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.2

 Total .................................................... 6.0

Type of Facility

 Cogenerator Qualifying Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4

 Small Power Producer 

 Qualifying Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.4

 Exempt Wholesale Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.8

 Two or more of the above . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.7

 Cogenerator Non-Qualifying Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.3

 Noncogenerator Non-Qualifying Facility . . . . . . . . . . . . . . . . . . . . . . . . . 1.4

 Total .................................................... 6.0

Utility

Prime Mover

 Combustion (Gas) Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.6

 Combined Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.7

 Steam Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.6

 Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3

 Other .................................................... a 0.6

 Total .................................................... 15.8

 Other includes hydraulic turbines, internal combustion, jet engine, and wind turbine. a

 Notes: •Nonutility data are for facilities of 1 or more megawatts. •Planned capacity

additions do not mean the same thing for utilities that they do for nonutilities. For utilities,

a planned unit must be “utility authorized.” For nonutilities, a planned unit must have

obtained either (1) all environmental and regulatory approvals, (2) a signed contract for the

electric energy, or (3) financial closure on the facility. •Indefinitely postponed and canceled

units are not included. •Because nonutility facilities generally have needed shorter lead

times to finance and build than utility facilities, and because utilities are required to plan for

future load, nonutility plans for facilities are likely to be less comprehensive than those for

utilities, especially for later years. •Nameplate capacity is used for comparison to nonutilities, instead of the more commonly used net summer capability, because net summer

capability is not collected for nonutilities. •Sum of components may not equal total due to

independent rounding. 

 Source: Utility Data: Energy Information Administration, Form EIA-860, “Annual Electric Generator Report,” (1995). Nonutility Data: Energy Information Administration, Form

EIA-867, “Annual Nonutility Power Producer Report,” (1995).

Table C3. Planned Nameplate Capacity Additions in 1995 by Prime Mover

and Type of Facility for the Electric Power Industry, 1996-1999

(Gigawatts)
Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update 129

Table C4. Capacity and Generation Statistics for the Electric Power Industry, 1995

Statistic Utility Nonutility Total U.S.

Nameplate Capacity by Census Division (gigawatts) a

 New England ........................................ 23.4 5.0 28.4

 Middle Atlantic ....................................... 84.2 12.5 96.6

 East North Central .................................... 125.3 5.9 131.2

 West North Central .................................... 59.0 1.2 60.2

 South Atlantic ........................................ 149.0 13.0 162.0

 East South Central .................................... 64.7 2.1 66.7

 West South Central ................................... 110.0 13.9 123.9

 Mountain ............................................ 53.6 2.8 56.4

 Pacific .............................................. 81.4 13.9 95.2

 Total .............................................. 750.5 70.3 820.8

Generation by Fuel (billion kilowatthours) b

 Coal ................................................ 1,652.9 57.7 1,710.6

 Petroleum ........................................... 60.8 17.0 77.8

 Natural Gas .......................................... 307.3 210.3 517.6

 Nuclear ............................................. 673.4 c 673.4

 Hydroelectric ......................................... 293.7 14.8 308.4

 Geothermal / Solar / Wind . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.8 13.9 18.7

 Biomass / Other ..................................... d 1.6 60.8 62.4

 Total .............................................. 2,994.5 374.4 3,369.0

Planned Capacity Additions by Year (gigawatts) e

 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3 2.6 8.0

 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.9 0.8 2.8

 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6 0.5 4.1

 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.9 2.0 6.9

 Total .............................................. 15.8 6.0 21.7

 Nameplate capacity is used instead of the more commonly used net summer capability because net summer capability is not a

collected for nonutilities.

 Generation for utilities is net of plant use and for nonutilities is gross generation. b

 Nuclear generation for nonutilities is included in the Other category. c

 Includes wood, wood waste, peat, wood liquors, railroad ties, pitch, wood sludge, municipal solid waste, agricultural waste, straw, d

tires, landfill gases, tall oil, digester gas, other waste, hydrogen, sulfur, batteries, chemicals, fish oil and spent sulfite liquor. Also

includes nuclear for nonutilities.

 For nonutilities, a planned unit must have obtained (1) all environmental and regulatory approvals, (2) a signed contract for the e

electric energy, or (3) financial closure on the facility. Because nonutility facilities generally have needed shorter leadtimes to

finance and build than utility facilities, and because utilities are required to plan for future load, nonutility plans for facilities are likely

to be less comprehensive than those for utilities, especially for later years. For utilities, a planned unit must only be “utility

authorized.”

 Note: •Sum of components may not equal total due to independent rounding. •Nonutility data are for facilities of 1 or more

megawatts. •Indefinitely postponed and cancelled units are not included in planned capacity additions. •Nonutility combined cycle

units are included with their constituent prime movers.

 Source: Utility Data: Capacity by Census Division and Planned Capacity Additions, Energy Information Administration, Inventory

of Power Plants in the United States 1995, DOE/EIA-0095(95) (Washington, DC, December 1996), Tables 16 and 7, respectively.

Generation by Fuel, Energy Information Administration, Electric Power Annual 1995, Volume I, DOE/EIA-0348(95)/1 (Washington,

DC, July 1996),Table 8. Nonutility Data: Capacity by Census Division and Generation by Fuel,Energy Information Administration,

Electric Power Annual 1995, Volume II, DOE/EIA-0348(95)/2 (Washington, DC, December 1996),Tables 54 and 58, respectively.

Planned Capacity Additions, Energy Information Administration, Form EIA-867, “Annual Nonutility Power Producer Report,” (1995).
130 Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update

Census Division and State Utility Nonutility U.S. Total

New England ........................... 76.0 29.4 105.4

 Connecticut ........................... 26.9 4.8 31.7

 Maine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.7 7.6 10.3

 Massachusetts ......................... 27.0 11.0 38.0

 New Hampshire ........................ 13.9 1.6 15.5

 Rhode Island . . . . . . . . . . . . . . . . . . . . . . . . . . 0.7 4.0 4.6

 Vermont . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.8 0.3 5.2

Middle Atlantic .......................... 297.2 69.8 367.0

 New Jersey ............................ 27.1 18.8 45.9

 New York ............................. 101.2 33.5 134.7

 Pennsylvania .......................... 168.9 17.5 186.4

East North Central ....................... 531.7 28.4 560.1

 Illinios ................................ 145.2 4.0 149.1

 Indiana ............................... 105.2 4.3 109.5

 Michigan .............................. 92.5 15.6 108.1

 Ohio ................................. 137.9 1.6 139.4

 Wisconsin ............................. 51.0 3.1 54.1

West North Central ....................... 242.6 4.7 247.3

 Iowa ................................. 33.5 1.2 34.7

 Kansas ............................... 38.2 0.2 38.4

 Minnesota ............................. 42.5 2.8 45.3

 Missouri .............................. 65.4 0.3 65.7

 Nebraska ............................. 25.3 * 25.3

 North Dakota .......................... 28.8 0.2 29.0

 South Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . 8.8 -- 8.8

South Atlantic .......................... 606.9 57.6 664.6

 Delaware . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3 0.8 9.1

 D.C. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.2 -- 0.2

 Florida ............................... 147.2 21.2 168.4

 Georgia .............................. 102.0 6.3 108.3

 Maryland ............................. 44.7 1.8 46.4

 North Carolina .......................... 96.1 10.8 106.9

 South Carolina ......................... 78.4 2.6 81.1

 Virginia ............................... 52.7 10.8 63.6

 West Virginia .......................... 77.3 3.4 80.7

East South Central ....................... 294.4 12.7 307.1

 Alabama .............................. 99.6 6.3 105.9

 Kentucky ............................. 86.2 * 86.2

 Mississippi ............................ 26.4 2.8 29.2

 Tennessee ............................ 82.3 3.6 85.9

West South Central ...................... 414.7 83.2 497.9

 Arkansas ............................. 39.5 2.6 42.1

 Louisiana ............................. 65.6 20.2 85.8

 Oklahoma ............................. 48.0 5.0 53.0

 Texas ................................ 261.7 55.3 317.0

Mountain .............................. 258.3 12.3 270.6

 Arizona ............................... 69.0 0.9 69.8

 Colorado .............................. 32.7 3.1 35.7

 Idaho ................................ 10.1 1.8 11.9

 Montana .............................. 25.4 0.6 26.0

 Nevada ............................... 20.0 4.1 24.1

 New Mexico ........................... 29.4 0.4 29.8

 Utah ................................. 32.1 0.7 32.8

 Wyoming ............................. 39.7 0.6 40.3

Pacific Contiguous ...................... 261.6 70.9 332.4

 California ............................. 121.9 62.8 184.7

 Oregon ............................... 44.0 1.3 45.4

 Washington ........................... 95.7 6.7 102.4

Pacific Noncontiguous ................... 11.0 5.6 16.6

 Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.8 1.2 6.1

 Hawaii . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2 4.3 10.5

United States ........................... 2994.5 374.4 3369.0

 *Number less than 0.05 rounded to zero.

 --=Not applicable. (There are no nonutility generators in South Dakota or the District of Columbia.) 

 Notes: •Sum of components may not equal total due to independent rounding. •Nonutility data are for facilities of 1 or more megawatts.

 Source: Utility Generation: Energy Information Administration, Electric Power Annual 1995,Volume I, DOE/EIA-0348(95)/1 (Washington, DC, July 1996),

Table 9. Nonutility Generation: Energy Information Administration, Electric Power Annual 1995, Volume II, DOE/EIA-0348(95)/2 (Washington, DC,

December 1996), Tables 58 and 59.

Table C5. Electric Power Industry Generation by Census Division and State, 1995

(Billion Kilowatthours)
Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update 131

Table C6. Statistics of the Utility Sector of the Electric Power Industry, 1970-1995

Year

Nameplate

Capacitya

(gigawatts)

Generation

(billion

kilowatthours)

Generation by Fuel

(billion kilowatthours)

Fossil Fuel Pric

(dollars per million 

Coal Nuclear 

Natural

Gas Petroleum

Hydroelectric Otherd Coal Petroleum 

1970 ........... 341.6 1,532 704 22 373 184 248 1 0.31 0.41 

1971 ........... 368.9 1,613 713 38 374 220 266 1 0.36 0.57 

1972 ........... 398.6 1,750 771 54 376 274 273 2 0.38 0.64 

1973 ........... 442.4 1,861 848 83 341 314 272 2 0.41 0.78 

1974 ........... 477.6 1,867 828 114 320 301 301 3 0.71 1.87 

1975 ........... 508.3 1,918 853 173 300 289 300 3 0.82 1.99 

1976 ........... 531.0 2,038 944 191 295 320 284 4 0.85 1.95 

1977 ........... 560.2 2,124 985 251 306 358 220 4 0.95 2.19 

1978 ........... 579.2 2,206 976 276 305 365 280 3 1.12 2.13 

1979 ........... 598.3 2,247 1,075 255 329 304 280 4 1.22 2.98 

1980 ........... 613.5 2,286 1,162 251 346 246 276 6 1.35 4.25 

1981 ........... 634.8 2,295 1,203 273 346 206 261 6 1.53 5.32 

1982 ........... 650.1 2,241 1,192 283 305 147 309 5 1.65 4.83 

1983 ........... 658.2 2,310 1,259 294 274 144 332 6 1.66 4.60 

1984 ........... 672.1 2,416 1,342 328 297 120 321 9 1.66 4.82 

1985 ........... 698.1 2,470 1,402 384 292 100 281 11 1.65 4.24 

1986 ........... 707.7 2,487 1,386 414 249 137 291 12 1.58 2.42 

1987 ........... 718.1 2,572 1,464 455 273 118 250 12 1.51 2.97 

1988 ........... 723.9 2,704 1,541 527 253 149 223 12 1.47 2.41 

1989 ........... 730.9 2,784 1,554 529 267 158 265 11 1.45 2.85 

1990 ........... 735.1 2,808 1,560 577 264 117 280 11 1.45 3.30 

1991 ........... 740.0 2,825 1,551 613 264 111 276 10 1.45 2.46 

1992 ........... 741.7 2,797 1,576 619 264 89 240 10 1.41 2.47 

1993 ........... 744.7 2,883 1,639 610 259 100 265 10 1.39 2.36 

1994 ........... 746.0 2,911 1,635 640 291 91 244 9 1.36 2.41 

1995 ........... 750.5 2,995 1,653 673 307 61 294 6 1.32 2.59 

 Nameplate capacity is used for comparison to nonutilities, instead of the more commonly used net summer capability, because net summer capability is not co

a

 The coal price is the average price of all coal types, and the petroleum price is the average price of heavy oil. (Heavy oil includes Fuel Oil Nos. 4, 5, and 6, an

b

 Retail price of electricity sold by electric utilities. Data for 1979 and earlier are for Classes A and B privately owned electric utilities only; data for 1980 and forward ar

c

whose electric operating revenues were $100 million or more during the previous year. Other includes geothermal, solar, wind, waste, and wood. d Note: •Sum of components may not equal total due to independent rounding. •Retail price for 1995 is preliminary. Sources: Capacity: 1970-1981—Energy Information Administration, 1982 Annual Energy Review, DOE/EIA-0384(82) (Washington, DC, April 1983), p. 159. 19

Administration, Inventory of Power Plants in the United States 1995, DOE/EIA-0095(95) (Washington, DC, December 1996), Table 1, and previous issues. Gen

Information Administration, Annual Energy Review 1995, DOE/EIA-0384(95) (Washington, DC, July 1996), Table 8.3. 1995—Energy Information Administration, Electr

I, DOE/EIA-0348(95)/1 (Washington, DC, July 1996), Table 8. Fuel Prices: 1970-1990—Energy Information Administration, State Energy Price and Expenditu

1995—Federal Energy Regulatory Commission, FERC Form 423, “Monthly Report of Cost and Quality of Fuels for Electric Plants.” Retail Price: Energy Information A

Review 1995, DOE/EIA-0384(95) (Washington, DC, July 1996), Table 8.11.
Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update 132Table C7. Statistics of the Nonutility Sector of the Electric Power Industry, 1970-1995 Year Nameplate Capacity (gigawatts) Generation (billion kilowatthours) Generation by Fuel (billion kilowatthours) Fo

(dol

Total Nonutility Usea Deliveries to Utilitiesb Coal Natural Gas Renewable / c Waste Otherd Coale 

1970 ...... h 19

i 108

i NA NA NA NA NA NA 0.44 

1971 . . . . . . . 19.3 103.2 NA NA NA NA NA NA 0.47 

1972 . . . . . . . 18.8 104.5 NA NA NA NA NA NA 0.51 1973 . . . . . . . 19.4 102.6 NA NA NA NA NA NA 0.53 1974 . . . . . . . 19.4 101.6 NA NA NA NA NA NA 0.99 1975 . . . . . . . 19.2 85.3 NA NA NA NA NA NA 1.28 1976 . . . . . . . 19.1 87.1 NA NA NA NA NA NA 1.25 1977 . . . . . . . 19.2 87.5 NA NA NA NA NA NA 1.31 1978 . . . . . . . 19.4 79.0 NA NA NA NA NA NA 1.46 1979 . . . . . . . 17.4 71.3 NA NA NA NA NA NA 1.55 1985 ...... h 22.9 98.5 70.2 28.3 18.2 33.6 39.7 7.1 1.81 

1986 . . . . . . . 25.3 112.0 71.3 40.7 20.5 40.0 46.0 5.5 1.75 1987 . . . . . . . 30.0 146.6 94.0 52.6 22.3 56.8 53.5 14.0 1.64 1988 . . . . . . . 33.7 174.3 104.1 70.2 31.9 70.0 67.2 5.1 1.61 1989 ...... h 36.6 187.4 106.1 81.2 31.5 98.9 49.4 7.5 1.61 1990 ....... 42.9 217.2 111.0 106.2 32.1 116.7 58.2 10.2 1.63 

1991 ....... 48.2 248.4 119.3 129.1 40.6 131.3 65.0 11.5 1.62 

1992 ...... h 56.8 296.0 131.6 164.4 47.4 158.8 75.3 14.5 1.62 

1993 ....... 60.8 325.2 137.8 187.5 53.4 174.3 81.0 16.6 1.59 

1994 ....... 68.5 354.9 150.2 204.7 59.0 192.2 85.0 18.6 NA 

1995 ....... 70.3 374.4 157.9 216.5 57.7 210.3 85.7 20.8 NA 

 Consumed onsite by the nonutility or delivered to other nonutilities. a

 Deliveries to utilities for resale. b Renewable energy sources include hydroelectric, wind, solar, geothermal, and wood resources. c Other includes all other fuels, including petroleum, multiple unit projects for which the primary energy source varied among the units, and projects which did no

d

source. The coal price is the price of steam coal to the industrial sector. e The petroleum price is the price of residual fuel oil to the industrial sector. f The natural gas price is its price to the industrial sector. g These data series were compiled from several sources resulting in some inconsistancies in category definitions over time. 1980-1984 are not included because no

h

for those years. Nonutility data for 1970 through 1979 represent capacity and generation in the industrial sector for plants of 10 megawatts or more only. Nonutilinclude all nonutilities. Nonutility data for 1989 through 1991 include nonutility facilities of 5 or more megawatts. Nonutility data for 1992 through 1995 include nmegawatts. Sum of components may not equal total due to independent rounding. Breakdown of generation assumes no nonutility receipts from utilities are reso 1970 nonutility capacity and generation data are available to whole numbers only. i NA = Not available. Notes: •Sum of components may not equal total due to independent rounding. •Breakdown of generation assumes no nonutility receipts are resold. Sources: Capacity and Generation: 1970-1979—Federal Power Commission, Form 4, “Monthly Power Plant Report.” 1985-1988—Edison Electric Institute, Stati

Utility Industry/1991 (Washington, DC, November 1992), pp. 7 and 15. 1989-1995—Energy Information Administration, Electric Power Annual 1995, Volume II, DOE

DC, December 1996), Tables 52, 54, and 58, and preceeding issues, and Form EIA-867, “Annual Nonutility Power Producer Report.” Generation by Fuel: 1985-19

1986 Capacity and Generation of Non-Utility Sources of Energy (Washington, DC, July 1988), pp. 78 and 79. 1987-1988—Edison Electric Institute, 1988 Capacity 

Sources of Energy (Washington, DC, December 1989), pp. 55 and 56. 1989-1995—Energy Information Administration, Electric Power Annual 1995, Volume II, DOE

DC, December 1996), Table 58 and preceeding issues. Fuel Prices: 1970-1984—Energy Information Administration, State Energy Price and Expenditure Data System

Information Administration, Annual Energy Review 1995, DOE/EIA-0384(95) (Washington, DC, July 1996), Table 3.7.
Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update 133

Table C8. Average Nameplate Capacity and Number of Utility-Operated Coal-Fired

Steam Turbine Units by Historical or Planned Year of Commercial

Operation, 1970-2005

Year

Average Capacity

(Megawatts) Number of Units

1970 ................................. 361.7 34

1971 ................................. 524.8 25

1972 ................................. 453.5 28

1973 ................................. 566.9 29

1974 ................................. 600.6 21

1975 ................................. 600.7 18

1976 ................................. 456.8 20

1977 ................................. 549.2 22

1978 ................................. 473.5 27

1979 ................................. 469.3 22

1980 ................................. 590.7 26

1981 ................................. 454.5 23

1982 ................................. 518.1 21

1983 ................................. 454.4 14

1984 ................................. 646.0 16

1985 ................................. 534.4 12

1986 ................................ 502.2 14

1987 ................................. 547.1 7

1988 ................................. 224.8 6

1989 ................................. 965.5 3

1990 ................................. 296.9 4

1991 ................................. 614.0 5

1992 ................................. 210.0 3

1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- --

1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- --

1995 ................................. 365.0 3

1996 ................................. 328.1 4

1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- --

1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- --

1999 ................................. 300.0 1

2000 ................................. 800.9 1

2001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- --

2002 ................................. 546.0 1

2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- --

2004 ................................. 290.0 2

2005 ................................. 604.0 2

-- = No new units started or, in the case of 1996 and beyond, planned to enter commercial operation.

Notes: •The year of commercial operation is the year that control of the unit was turned over to the

dispatcher. •Includes all coal-fired steam turbine units active since 1970 and all units planned as of

January 1, 1996. •Indefinitely postponed and canceled units are not included in planned capacity

additions.

Source: Energy Information Administration, Form EIA-860, “Annual Electric Generator Report”

(1995). 
134 Energy Information Administration/ Changing Structure of the Electric Power Industry: An Update

Year

Fluidized Bed Steam

Turbine Other Steam Turbinea Combustion Turbine Windfarms

Average

Capacity

(Megawatts)

Number

of Units

Average

Capacity

(Megawatts)

Number 

of Units

Average

Capacity

(Megawatts)

Number

of Units

Average

Capacity

(Megawatts)

Number

of Units

1970 . . . . . . . . . . . . . . -- -- 20.4 13 8.9 6 -- --

1971 . . . . . . . . . . . . . . -- -- 14.8 10 W W -- --

1972 . . . . . . . . . . . . . . -- -- 14.3 16 W W -- --

1973 . . . . . . . . . . . . . . -- -- 10.6 4 -- -- -- --

1974 . . . . . . . . . . . . . . -- -- 11.7 23 W W -- --

1975 . . . . . . . . . . . . . . -- -- 8.3 7 3.8 5 -- --

1976 . . . . . . . . . . . . . . -- -- 21.4 13 W W -- --

1977 .............. W W 14.8 17 15.3 11 -- --

1978 . . . . . . . . . . . . . . -- -- 20.5 16 41.5 6 -- --

1979 . . . . . . . . . . . . . . -- -- 21.1 17 32.6 4 -- --

1980 . . . . . . . . . . . . . . -- -- 18.2 19 3.1 9 -- --

1981 . . . . . . . . . . . . . . -- -- 18.0 26 1.8 6 W W

1982 .............. W W 19.6 34 28.7 27 12.5 4

1983 . . . . . . . . . . . . . . -- -- 12.9 25 29.4 25 60.4 8

1984 . . . . . . . . . . . . . . -- -- 24.3 35 23.7 28 21.9 10

1985 .............. W W 17.8 64 36.0 46 12.0 17

1986 .............. 35.4 4 18.5 52 14.3 67 10.9 8

1987 .............. 28.9 7 23.6 69 28.8 66 12.9 13

1988 .............. 38.5 8 25.6 72 22.0 59 W W

1989 .............. 44.6 13 24.3 89 29.0 94 23.6 4

1990 .............. 79.5 9 36.4 69 39.9 68 32.4 5

1991 .............. W W 37.7 55 39.3 54 W W

1992 .............. 84.3 4 30.1 59 46.7 61 W W

1993 .............. W W 27.1 52 44.2 46 W W

1994 . . . . . . . . . . . . . . -- -- 52.8 48 82.9 45 W W

1995 .............. W W 45.0 26 34.6 29 -- --

1996 .............. W W 41.9 20 42.0 39 W W

1997 . . . . . . . . . . . . . . -- -- 38.3 6 95.0 5 -- --

1998 .............. W W 35.1 6 W W -- --

1999 .............. W W W W 75.0 4 -- --

 Other steam turbine units include steam portion of combined cycle, nuclear steam, geothermal steam, and solar steam. a

 W = Withheld to avoid disclosure of individual company data.

 -- = No new units started, or in the case of 1996 and beyond, planned to start operation.

 Notes: Combined cycle units are included with their constituent prime movers. Data include only units operating or planned on December 31,

1995. •Indefinitely postponed and canceled units are not included in planned capacity additions.

 Source: Energy Information Administration, Form EIA-867, “Annual Nonutility Power Producer Report,” (1995).

Table C9. Average Nameplate Capacity and Number of Nonutility-Owned Units by Selected Prime Mover and

Historical or Planned Year that Electricity First Generated, 1970-1999
Appendix D

Brief Characteristics of

the Oak Ridge Financial

Model (ORFIN)
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 137

Oak Ridge National Laboratory, ORFIN: An Electric Utility Financial and Production Simulator, ORNL/CON-431 (Oak Ridge, TN, March 259

1996).

Appendix D

Brief Characteristics of the

Oak Ridge Financial Model (ORFIN)

ORFIN is a simplified version of a utility integrated term power-purchase contracts, or a new resource (a

planning model developed by the Oak Ridge National utility-owned plant or a contract). New plants may be

Laboratory. The model includes a production-costing added in small increments each year to ensure that the

module, utility financial statements (income statement, utility meets its designated reserve requirements. The

balance sheet, and cash-flow statement), and a rate-design model matches production and loads for a peak period

module (functionalization, classification, and allocation of (that includes no planned outages) and an off-peak period

costs to customer classes). (where plants are derated so that their annual availability 259

ORFIN simulates a single utility interacting with a single rates). The production-costing results are then used by the

wholesale market. The utility serves bundled retail financial portions of ORFIN to estimate O&M

customers through its integrated generation, transmission, expenditures.

and distribution system. The utility also buys and sells

power on the wholesale market when economical, subject The dispatch module first calculates load-duration curves

to certain system constraints, such as the utility’s whole- for the peak and off-peak seasons. The resources are then

sale transmission capacity. Wheeling customers purchase sorted in order of their variable costs. Must-run plants are

electricity directly from the wholesale market but receive assigned a zero bid price for dispatching purposes. The

electricity through the utility’s transmission and distri- percentage of the season a plant operates is calculated for

bution (T&D) network. up to 22 power levels. For each season, these 22 points are

Figure D1 defines the boundaries of the assessment equivalent load duration curve for each plant. 

framework. To meet this framework, ORFIN contains

many user inputs to permit examination of the effects of After calculating the operating times for all plants for the

a wide variety of variables on utility production costs, year, ORFIN determines if it is economical to sell any

assets, incomes, losses, and rates. Table D1 lists the key excess power on the wholesale market or to displace some

categories of user inputs. The user provides information of its own production with wholesale purchases. The user

on the initial state of the utility. These initial conditions defines the wholesale market using up to four wholesale

include information on the utility’s power plants, power- prices for different portions of the year. ORFIN then

purchase contracts, operations and maintenance (O&M) compares the variable cost for each plant with the

costs, and customer characteristics. The user also specifies wholesale purchase and sale prices for each period. When

the initial fuel prices and wholesale prices and their a plant’s variable cost is lower than the current wholesale

escalation over time. This initial state of the utility defines sale price and the plant has excess capacity, the plant will

the base case. sell into the market. When its variable costs exceed the

The dispatch module uses data from each year to calculate then ORFIN backs down the plant and, instead, purchases

the generation, contract purchases, and wholesale-market wholesale power. ORFIN compares each possible

activity (purchases and sales) for the utility. The module transaction with the user-defined transmission-capacity

dispatches up to 10 distinct utility resources. These constraint and limits wholesale sales and purchases

resources can be utility-owned generating units, long- accordingly.

accounts for user-defined forced and planned outage

sorted by increasing power level before calculating the

wholesale purchase price and it is producing at that time,
Net Incomet 
 Revenuest

	 Expensest

n Costs 
 M

T

t
1

[(Net Incomebc, t 	 Net Incomerw, t) ÷ (1di

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

Source: Oak Ridge National Laboratory, Strategies to Address Transition Costs in the Electricity

Industry, ORNL/CON-431 (Oak Ridge, TN, August 1996).

Figure D1. Schematic Representation Defining ORFIN Assessment Framework

ORFIN’s income statement reflects the results of the transition costs are the sum of these annual differences,

utility’s operations for a calendar year. The income discounted to present value dollars.

statement includes detail about revenues, expenses, and

income. Income is the difference between revenues and

expenses. Revenues are the product of electricity sales and

prices, summed over the relevant customer classes. Operating expenses include production and nonproduction

costs, book depreciation, taxes, and interest payments.

Production expenses include fuel and O&M costs for the

utility’s power plants, power-purchase-contract costs, and

purchases and sales on the wholesale market. Net income

is the return to utility shareholders. 

ORFIN yields what is called a bottom-up ex ante admini- utility’s return on equity for the years t = 1 through year

strative valuation of transition costs. The annual transition T. Net Income is from the retail wheeling case for year

costs are the annual difference in net income between the t while Net Income is from the base case for the same

retail-wheeling scenario and the base case. The total year.

Transition costs are calculated as net present value at the

rw,t

bc,t
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 139

Table D1. Key Inputs to ORFIN

Nongeneration operating costs Transmission, distribution, customer service, A&G, O&M

($/year), and public-policy-program costs ($/year), and O&M

cost escalation percent per year

Nongeneration capital costs Transmission, distribution, and general capital costs ($/year,

$/customer, $/kW)

Power-purchase contracts Capacity (MW), offline date (year), forced and planned

outage rates (percent), fixed costs ($/kW-year), and variable

costs (¢/kWh)

Utility-owned generating units Capacity (MW), initial cost ($/kW), start and offline dates

(year), tax and book depreciation lives (years), forced and

planned outage rates (percent), fixed O&M cost ($/kW-year),

variable O&M cost (¢/kWh), O&M escalation rate (percent per

year), heat rate (Btu/kWh), fuel type, and fuel prices ($/MBtu)

by year

Wholesale-market prices Prices (¢/kWh) by time period (percent per year), escalation

rates (percent per year), difference between wholesale

purchase and sale price (¢/kWh), and transmission capacity

(MW)

Customers By class: number of customers, consumption (kWh/customermonth), load factor, growth rates (percent per year) in number

of customers and in per-customer consumption, and T&D

energy and demand losses

Retail wheeling Percentage of customers from each class that wheel by year,

percentage of A&G costs paid by wheelers, and ancillaryservice cost adder (¢/kWh)

Finances Long-term bonds and common equity (percent of total

capitalization and return in percent per year), inflation rate

(percent per year), federal/state income tax rate (percent),

revenue-sensitive tax rate (percent), property tax rate

(percent), frequency and type (historic vs future test year) of

rate cases, and regulatory assets

 A&G = Administrative and general.

 O&M = Operations and maintenance.

 MW = Megawatts.

 $/kW = Dollars per kilowatt.

 ¢/kW = Cents per kilowatt.

 Btu = British thermal unit.

 $/Mbtu = Dollars per million Btu.

 Source: Oak Ridge National Laboratory, Strategies to Address Transition Costs in the Electricity Industry, ORNL/CON-431 (Oak

Ridge, TN, August 1996).
Appendix E

Stranded Costs
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 143

Fixed costs represent the sum total of expenses (like interest, depreciation, taxes, and nonfuel operating and maintenance expenses) 260

that do not vary with the level of economic activity. Long-term power purchase agreements also imply that the utilities incur long-term fixed

payment obligations which they may or may not be able to meet fully in a changing market environment. 

Transmission and distribution activities will continue to be regulated. 261

For a additional details of these approaches, refer to Niagara Mohawk Power Corporation's filing with the New York Public Service 262

Commission in PSC Case Nos. 94-E-0098 and 94-E-0099, Phase II, Multi-Year Electric Rate, Restructuring and Retail Access Proposal. (Syracuse,

NY, October 6, 1995). Also, San Diego Gas and Electric Company, Comments of San Diego Gas and Electric Company on Proposed Policy Governing

Restructuring Electric Services Industry and Reforming Regulation, submitted to the California Public Utilities Commission in Docket No. R-94-04-

031 (San Diego, CA, June 8, 1994).

The assumption is that electricity prices will decline as a result of competition. 263

For example, the Massachusetts Electric Company in Massachusetts estimated the net present value of its stranded cost obligations to 264

be about $4.3 billion. These estimates, which were based on a set of assumptions used by the utility, were challenged in another assessment

report prepared for the Massachusetts Attorney General. That report showed that the Massachusetts operations of the utility will result in large

restructuring gains in the range of $1.0 billion to $3.0 billion. Refer to Resource Insight Inc., Estimation of Market Value, Stranded Investment

and Restructuring Gains (Boston, MA: April 17, 1996), p. 2. 

Appendix E

Stranded Costs

Methodologies for Estimating 

Stranded Costs

Utilities with power production costs higher than those

likely to prevail in the competitive market will be unable

to fully recover the fixed costs of generating facilities that

they own and operate to meet customer demand. Ac- 260

cordingly, the initial composition of stranded costs will be

dominated by assets related to a utility's generating

capacity.261

A utility can estimate its potential stranded/strandable

costs in one of two basic ways. It can compute the present

value of its assets and compare the resulting valuation

with its sunk or historical costs, or it can look at the loss in

revenue (for a given number of years in the future) as a

market price for electricity changes and compute the present value of stranded costs. These basic approaches can

be varied depending on when the estimates are made, i.e.,

before or after the commencement of wholesale and retail

wheeling and whether the estimates are made administratively or are determined by the market. These varying

considerations enable categorization of approaches into

bottom-up versus top-down, ex ante versus ex post, and

administrative versus market. 262

Bottom-Up Versus Top-Down

This approach looks at whether stranded costs are

estimated for individual assets or for the aggregate of

assets. The bottom-up approach computes the amount of

each investment (including contracts, regulatory assets,

social programs, and other stranded liabilities) that would

be stranded. This approach can provide valuable information (for consideration in adopting mitigation

strategies) with respect to those cost variables that have

critical impacts on costs. Its weakness lies in not being

able to encompass certain incumbent burdens.

The top-down approach calculates the difference in

revenues under a regulatory regime and those likely to

accrue with the commencement of competition. In this 263

approach, the totality of assets (including incumbent

burdens) can be taken into account.

Ex Ante Versus Ex Post

These approaches are based on when the estimates for

stranded/strandable costs are made, i.e., before or after

the commencement of transition to competition. 

The ex ante method provides projections (or forecasts) of

stranded/strandable costs before the start of competition.

It is based on embedded costs and projected market prices

from alternative sources. The validity of such forecasts

hinges on the legitimacy of a host of assumptions (such as

fuel prices, demand growth, load shapes, technological

advancements and others) incorporated in the process.264

Incorrect assumptions could lead to windfall gains or

losses. 
144 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Boston Edison, Industry Restructuring Plan, submitted to the Massachusetts Department of Public Utilities in Docket No. 96-23 (Boston, 265

MA, February 16, 1996).

By adopting the “revenues lost” approach, FERC also avoided including additional categories of costs in computing stranded costs. 266

Recommended categories for inclusion include fuel supply costs, purchased power costs (including qualifying facility costs), nuclear

decommissioning costs, and such other utility obligations (such as expenditures on social and environmental programs) that may possibly be

stranded.

The Massachusetts Department of Public Utilities, for example, would prefer that the investor-owned utilities in the State take steps 267

to mitigate stranded costs through the sale of generating assets on the presumption that while some generating assets may be undervalued

(in relation to their unamortized portion of the historical costs), others may be overvalued. Adoption of this procedure will provide an

opportunity to recover the net, nonmitigable stranded costs on their books as of August 16, 1995.

The ex post approach estimates stranded/strandable costs main disadvantage is that large blocks of assets cannot be

after competition is introduced and has made a start. sold easily and may tend to depress prices. Its

Since market prices are known in this approach, a greater applicability is also limited to marketable assets. 

degree of confidence can be placed in the estimates. The

appeal of this approach lies in its capability to indicate the

magnitude of strandable assets that move the utilities to

initiate actions toward adoption of feasible mitigation

strategies. In addition, the process establishes a benchmark for potential recovery.

Administrative Versus Market Approach

An administrative approach is based on negotiations

between the utility and the regulatory agencies in an

attempt to estimate the amount of stranded/strandable

assets. However, this approach suffers from the same

difficulties as the ex ante approach, in which assumptions

regarding future prices and asset values need to be made.

On the other hand, the market approach starts with

observations in the market and minimizes the problems

inherent in forecasting. Observed prices can, however, be

subject to market volatility, biasing the results in the

market approach. 

An alternative (in the market approach) is for a utility to

put its generating assets up for sale and secure a price

offered by the highest bidder. Stranded costs in this

approach are immediately determined as the difference

between the embedded price and the realized price. Its

265

In its recent filing with the Public Service Commission of

New York, the Niagara Mohawk Power Corporation

(NMPC) opted in favor of a hybrid approach for

estimating strandable costs, using several of the above

methods. Its preferred method will be ex ante, top-down,

and administrative. Revenue projections based on a

“business-as-usual” scenario will be compared with what

may be sustainable under competitive conditions. NMPC

will also use a bottom-up approach to identify the source

of deficit. In addition, the utility proposes to make ex post

adjustments to market electricity prices in an attempt to

fine tune the estimates. 

Table E1 provides possible combinations of the approaches discussed above. 

FERC's Methodology for Estimating

Stranded Cost Obligations

As indicated in an earlier chapter, FERC has adopted the

“revenues lost” approach in hopes of avoiding asset-byasset reviews to calculate recoverable stranded costs.266

Whether the State regulatory authorities will also adopt

this mode remains an open question.267

Table E1. Alternative Ways to Compute Stranded Commitments

Administrative Valuation Market Valuation

Ex ante Ex post Ex ante Ex post

Bottom-up ......... Asset-by-asset value Assets valued after Assets sold at auction After-the-fact

projections restructuring purchase-price

adjustment

Top-down .......... Projection of After-the-fact Bundles of assets Deferred valuation of

regulated rate by adjustment of spun off spun-off assets

customer class regulated prices

 Source: Oak Ridge National Laboratory, Estimating Potential Stranded Commitments for U.S. Investor-Owned Electric

Utilities, ORNL/CON-406 (Oak Ridge, TN, January 1995), p. 7.
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 145

Federal Energy Regulatory Commission, Order No 888, Promoting Wholesale Competition Through Open Access Non-discriminatory 164

Transmission Services by Public Utilities, Docket No. RM95-8-000, and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities,

Docket No. RM-94-7-001 (Final Rule, April 24, 1996), pp. 593-605.

 National Regulatory Research Institute, The Regulatory Treatment of Embedded Costs Exceeding Market Prices: Transition to a Competitive 165

Electric Generation Market—A Briefing Document for State Commissions (Columbus, OH, November 7, 1994), pp. 45-56.

 Price caps allow a utility to keep all or a share of the revenues resulting from cost-cutting efficiencies. Performance-based incentive rate-setting 166

attempts to link profits to desired results or targets. Both mechanisms enable utilities to reduce costs and/or attain efficiency gains and do not, therefore, shift

costs.

FERC's methodology for estimating the “stranded cost

obligation” (SCO) of a departing generation customer

takes the following form:

RSE = revenue stream estimate attributable

to the departing customer based on

the average of three prior year's

revenues

SCO = (RSE - CMVE) x L

where

 SCO = stranded cost obligation

CMVE = competitive market value estimate

either from sale of released capacity

or the average annual cost to the

customer of replacement capacity

and associated energy 

L = length of obligation (reasonable

expectation period).

The above formula is designed for determining stranded

costs associated with departing wholesale-generation

customers and retail-turned-wholesale customers. Its

application is subject to conditions such as stipulating a

cap on SCO, payment options, and others. The formula is

designed to ensure full recovery of legitimate, prudent,

and verifiable stranded costs subject to the requirement

that the utility takes steps to mitigate stranded costs. In

addition, the results create certainty for the departing

customer as well as incentives for parties to renegotiate

their existing requirements contracts.164

It is just as possible that FERC's formula approach will

also raise issues in the process of estimating stranded

costs. It will not be easy to estimate the CMVE based on

a market analysis. Establishing that the utility had a

reasonable expectation of serving the customer may also

be controversial.

Mitigation Strategies

Classification Schemes

It is possible to view mitigation strategies from the

perspective of whether they are transaction or nontransaction related. This is the approach adopted in a

study prepared by the National Regulatory Research

Institute (NRRI) as a briefing document for State

commissions. The classification adopted in the NRRI

study is as follows:165

Transaction-Related Recovery Devices

 Access charge tied directly to continued

 transmission or distribution service

 Exit fees charged to departing customers but

unrelated to costs incurred on behalf of those

customers

 Exit fees charged to departing customers and

calculated to recover costs incurred on behalf of

those customers

 A share of net generation savings realized by

departing customers over time.

Non-Transaction-Related Recovery Devices

 Shifting costs to captive customers

 Charging ratepayers above-cost prices where

 market exceeds cost

 Accelerated and decelerated depreciation

 Price cap on performance-based rates.166
146 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 In view of the relative importance of this subject, the Energy Information Administration (EIA) commissioned the Oak Ridge National Laboratory 271

(ORNL) to undertake research on this topic. A part of this chapter is based on the recently completed report received by EIA from ORNL. Lester W. Baxter,

the principal investigator, supported by Stan Hadley and Eric Hirst (from ORNL) participated in the research and in providing the results. For further details,

see Oak Ridge National Laboratory, Strategies to Address Transition Costs in the Electricity Industry, ORNL/CON-431 (Oak Ridge, TN, July 1996).

 Another benefit of divestiture may be to foster the transfer of generation assets to corporate entities that may be able to operate them more eficiently 272

than the current owner.

 Federal Energy Regulatory Commission, Electric Utility Depreciation Practices (Washington, DC, December 1980). 273

Broader Bases

 Entrance fees charged to new generation

 All sellers pay a per-kilowatthour tax on

generation

 Taxes to include credits for financial writedowns

or trust funds to subsidize buyout of contracts

from nonutility generators.

Each of the above 11 strategies is evaluated to determine

its applicability in comparison with other strategies. The

criteria used include considerations of static and dynamic

efficiency, consistency with evolution to a competitive

market, consistency with regulatory quid pro quo, and

difficulties in implementation.

The number of suggested mitigation strategies has

proliferated since the release of the FERC's declared intent

to actively promote electricity competition in the wake of

the EPACT. The following recent listing of 34 strategies is

based on a review of the filings at FERC, restructuring

proceedings, and a survey of the literature. This study

classifies them into six major categories.271

Market Actions

Open Markets: Maximizes competitive pressures on

electricity suppliers by ensuring a rapid transition to retail

wheeling coupled with the elimination of monopoly franchises. The financial consequences of this strategy for

utility shareholders are severe.

Delay Competition: Assumes the retail process to begin

in a staged fashion starting with some selected customers

getting access to alternative suppliers initially and

extending it to others subsequently. A variant of this

strategy is to give all customers access at the same time,

but to delay the onset of access by several years. This

strategy contrasts sharply with the preceding strategy, but

reduces financial burdens on utility shareholders.

Divest Utility Plant: Envisions divestiture of a utility's

generating assets to provide a readily identifiable market

value for the assets and thus a valuation of its stranded

costs. This strategy is deemed necessary to ensure

competitive markets and to reduce potential conflicts

between unregulated and regulated operations. Reduction of market power is touted as another advantage.272

Variants of the divestiture strategy include a rate-base

spinoff, where the utility retains only that portion of its

generation needed to serve its retail customers and sells

the remainder. Another version extends divestiture to

sale of transmission assets, in the belief that such assets’

market value exceeds their book value, and that this may

be used to offset losses resulting from the sale of

generating assets at below-book market values.

Mergers: Reduces potential stranded costs by promoting

operating efficiencies or improving marketing opportunities.

Market Excess Capacity or Energy: Assumes that capacity freed by departing customers can be marketed,

thereby augmenting revenue accruals and lowering

stranded cost estimations.

Depreciation Options

Depreciation accounting enables recovery of original

plant cost over the estimated life of the plant of about 30

to 40 years. Nearly 97 percent of the utilities apply a

straight-line recovery method for ratemaking purposes.273

Depreciation expenses are reflected in the prices

customers pay for electricity.

Accelerate Depreciation of Utility Assets: Permits

utilities to recover their plants' costs in a shorter period of

time in comparison with the straight-line method. 

Adoption of this procedure tends to raise rates (expenses)

over the shortened depreciation schedule, with a corresponding decline later on. Accelerated depreciation techniques are recommended for specific nonmarketable
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 147

 Regulatory assets include previously incurred costs that have been deferred for recovery in future rates with the concurrence of regulatory authorities. 274

Such a classification is permissible under the provisions of Financial Accounting Standard (FAS) No. 71. Thus, regulatory assets include any costs that could

or would have been otherwise expensed under standard accounting conventions. Examples of its components include regulatory tax assets recoverable

through future rates, deferred finance charges, deferred environmental charges, unamortized property losses, unamortized demand-side management

expenditures, certain post-retirement benefit costs, canceled or abandoned plants for which recovery of unamortized costs has been allowed, and others.

 As an example, the California Public Utility Commission (CPUC) granted a request from Southern California Edison (SCE) to accelerate the recovery 275

of SCE's investment in the San Onofre nuclear power plant. In response to complaints that such an action would come at the expense of the existing

ratepayers, the SCE modified its proposal to include deferred depreciation for transmission and distribution assets (which are likely to remain monopoly

services).

 A. P. Della Valle and M. O. Bidwell, Jr., “Restructuring Rates Creates Value and Reduces Stranded Costs,” Electricity Journal (December 1995), 276

pp. 19-25.

assets, such as those under the category of regulatory needs to charge to collect that revenue. However, if the

assets. utility is instead permitted to hold the rates constant (e.g., 274

Transfer Depreciation Reserves: Under this method, (for reimbursement to shareholders) can be a trandepreciation reserves from transmission and distribution sition-cost strategy. Shareholders earn the lower return

categories are transferred to generation assets. Net plant (e.g., 8 percent) and the utility uses the balance (e.g., 2

valuation of generating assets is thereby reduced, with a percent), as embedded in current rates, to offset sunk

corresponding increase in the net valuation of the above obligations.

assets.

Accelerated Depreciation Offset with Decelerated of utilities cross-subsidizing rates from one customer class

Depreciation: This is the same as “accelerated

depreciation” but with a countervailing proviso that

decelerates depreciation charges in asset areas that are

risk free (such as transmission and distribution assets).

This procedure constrains (or offsets) increases in rates.275

Economic Levelization: When a plant or an asset is

added to the rate base, a utility recovers depreciation

together with income on its full value. The sum of these

two is always higher in the initial years and declines continually over time (other things being equal) as the asset

valuation is reduced by the amount depreciated each

year. This regulatory approach tends to make the process

“front-end loaded.” Economic levelization keeps the depreciation expense of a resource constant (in real dollars)

over time. Thus, economic levelization has the opposite

effect of accelerated depreciation and may be viewed as a

strategy during the transition to promote sales.

Ratemaking Actions Unbundle Rates: In addition to the unbundling of rates

These strategies are linked with regulatory ratemaking

and its linkage with recovery of embedded plant costs.

Adjust Utility Returns: Reducing a utility's authorized

return will lower its revenues, earnings, and rates. For

example, reducing the utility's authorized return from 10

percent to 8 percent for a given rate base will reduce

earnings to shareholders by 20 percent, thus lowering the

utility's revenue requirement and the rates the utility

at 10 percent), then reducing a utility's authorized return

Eliminate Subsidies: This concept is based on the notion

to the other. Eliminating subsidies and/or discounts will

enable “getting the prices right.” Elimination of subsidies

would permit customers to get a better indication of the

utility's cost structure relative to alternative suppliers.

Restructure Rates: The suggested remedy is to design a

two-part rate structure for all ratepayers, made up of

energy rates approximating the utilities' marginal costs

and a fixed charge covering their fixed costs. Such a rate

structure reflects prices accurately and allows the utility to

compete successfully during the time when it is a low-cost

provider, thus avoiding uneconomic bypass of its

generation system. It is claimed that this strategy can

create a substantial value for the utilities by increasing the

level of revenues during the transition to a fully

competitive environment. Note that this is one way in 276

which rates could be restructured. There are several other

possibilities.

suggested in the above strategy, rates could be further unbundled to include costs for transmission and distribution

and ancillary services. It is claimed that charging

unbundled rates for separate categories of services can

lead to a reduction in stranded costs during transition.

Allow Rate Flexibility: The intent is to endow the

utilities with flexibility in setting customer rates (prices)

with the objective of reducing the level of stranded/strandable costs. 
148 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Performance-Based Ratemaking (PBR): Under this

strategy, traditional cost-of-service ratemaking is replaced

by either a price or revenue cap, which is adjusted periodically for inflation and a minimum productivity improvement target. This alternative provides the utilities with

inducement to reduce costs and improve productivity and

tends to shift risks from customers to the utility. To the

extent that a portion of the savings can be used to offset

potential strandable costs, PBR offers a viable solution. 

Disallow Costs: Regulatory authorities could simply ductions could be shared between the ratepayers and the

disallow certain costs from the rates. These disallowances shareholders.

could be related to above-market generating costs or other

areas of utility operations deemed to be high relative to Reduce Operating Costs: Options available to achieve

the industry. This strategy would be effective only in cases reductions in operating costs include reducing plant heat

for costs not yet included in rates. rates, trimming other operating and maintenance

Explicitly Shift Costs to Captive Customers: The intent

is to shift costs to captive customers rather than to Reduce Public Policy Program Costs: These include

departing customers. This is a rather unpopular strategy energy efficiency, low-income assistance, and research

and is unlikely to be implemented because it mitigates and development programs. Cutbacks in these programs

stranded costs that might otherwise be allocated to could result in savings for a utility.

noncaptive customers and/or to the utility’s shareholders.

Exit Fees: Requires departing customers to pay exit fees reduced either by renegotiating contracts or by using

based, for the most part, on the concept of embedded thebuyout option where feasible. A number of investorcosts. Exit fees could be a lump sum payment or owned utilities are using this option to lower their overall

converted into a stream of payments. In dealing with the costs.

subject of stranded cost recovery, this strategy enjoys the

support of FERC. Financial Writedowns: A writedown is a charge against

Net Generation Savings: This strategy aims to share the a diminution in earnings for the shareholders. Under a

generation savings realized by the departing customers. writedown, the possibility of capital cost recovery in the

Net generation savings, in this case, are defined as the future is eliminated. The strategy, however, permits a

difference between a utility's embedded cost of generation utility to take action on its own to become more

and the generation price obtained by the departing competitive (by paring historical costs of uneconomic

customer. Under this approach, a portion of the savings plants).

realized by the exiting customer is used to offset stranded

costs. Proponents of this approach realize the difficulty in

its implementation, since it may require the coordination

of more than one regulatory authority.

Access Charge: An access charge could be levied for

transmission and distribution services. This charge, which

could be fixed or variable (i.e., depending on the level of

usage), could be structured to include an element of

stranded cost recovery either on the basis of a lump sum

payment or as a regular payment stream. Difficulties may

arise in its implementation due to interjurisdictional

problems, since transmission rates need to be determined

by FERC and distribution rates need to be handled by the

States. The appeal of access charges lies in the fact that all

customers contribute to the recovery of stranded costs.

Utility Cost Reductions

If savings resulting from utility cost reductions are to be

applied to reduce or offset strandable costs, regulatory

approval becomes necessary. Cost reductions may be

viewed as efficiency gains provided they do not affect the

quality or reliability of service to an unacceptable degree.

Accordingly, cost reduction measures are welcome, since

they do not involve shifting costs among different segments of the economy. Savings resulting from cost reexpenses, or retiring uneconomic plants. 

Reduce Power Purchase Costs: These costs can be

income implying that the extent of the writedown reflects

Tax Measures

Options that include tax measures have an intuitive

appeal, because taxes are deemed to be instruments of

public policy. Promoters of tax-based options point out

that the benefits of promoting competition in electricity

trade will be enjoyed by the economy as a whole.

Accordingly, the costs of transition should also be borne

by the entire economy.

Consumption Tax: A consumption tax (similar to an

excise or a sales tax) could be implemented either at the

State or the Federal level. Revenues so received could be

segregated in a trust fund for specific uses to include

subsidizing the buyout of above-market power purchase
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 149

 Collecting the $100 billion over a 10-year period implies an annual payment of $15 billion, assuming an 8-percent rate of interest. Demand for power 277

is assumed to grow by 2 percent annually from its current levels (sales in 1994 were about 2.9 trillion kilowatthours). Thus, dividing $15 billion by about

3.2 trillion kilowatthours yields about 0.5 cents per kilowatthour. 

 State of Washington, Engrossed Senate Bill 5692, Conservation Investment by Public Utilities, approved on April 1, 1994. Puget Power had carried 278

conservation investments (as regulatory assets) on its books with the regulatory promise of recovery through the rate base. No rate impact is envisaged, since

the current customer rates permit for recovery of such investments. Passage of the legislation permits the utility to classify the regulatory asset as a statutory

asset with resulting benefits in financing at a lower rate.

contracts and other nonmarketable regulatory assets.

Assuming the present value of strandable costs to be $100

billion, a consumption tax of 0.5 cents per kilowatthour

will be necessary for a 10-year period. It is unlikely that 277

such a tax will be seriously considered in the near future,

because political support may not be secured for its

implementation

National Tax for Nuclear Plants: This strategy is similar tition may permit utilities to lower the level of stranded

to the imposition of a Federal tax, except that it focuses on costs. Except as another way of delaying or eliminating

strandable costs associated with nuclear power plants. competition, it is difficult to see how this strategy

Federal taxation is recommended since Federal policies addresses stranded or transition costs.

had a major role in the promotion of nuclear power.

Production Tax: This tax is similar to the consumption tax obligation to serve, utilities may retire uneconomic assets

except for the difference that producers of power pay the or reduce excess capacity and thereby lower the level of

tax instead of the customers. This makes the collection potential strandable costs.

process simpler and perhaps less controversial.

Tax Reduction: A tax-reduction strategy can take many legislation that would permit statutory recovery of

forms. This strategy was initially conceived as a reduction stranded costs. Puget Power in Washington State, for

in the utility’s marginal income tax rate at the State (where example, has been assured of the recovery of its demandapplicable) or Federal level. However, a tax reduction can side management-related expenditures (its largest

so target a State’s gross revenue tax collected by the regulatory asset) in this manner. The legislation enacted

utility. Because independent power producers do not in the State of Washington creates a new property right

collect this tax, a gross revenue tax acts to further differ- called the “bondable conservation investment,” under

entiate utility prices from prices of alternative suppliers. which customer rates permit the recovery of demand-side

In addition, some jurisdictions set higher property tax management costs incurred by the utility.

rates for utility-owned generators than for nonutility

generators. These higher tax rates contribute to differ- Entrance Fee for Returning Customers: Customers that

ences between costs (and prices) for utility-owned and depart the utility system and subsequently elect to return

nonutility generators. Setting a common property tax rate become liable to be charged an entry fee. The entrance fee

for all generators within the same jurisdiction (either by could be structured to cover the transition costs incurred

lowering the utility’s property tax rate or raising the during the period the customer purchased power from

nonutility’s rate) will reduce the difference in generation alternative suppliers.

costs (and prices) between suppliers.

Tax Deduction: Under this strategy, a tax deduction or facilities coming on line after restructuring could be

credit for uneconomic and unamortized investments in charged a fee to enter the market. Practical difficulties are

utility plants that utilities subsequently retire may be likely to be encountered if this proposal is ever impleallowed. Such a deduction would have to be beyond (i.e., mented. For example, who will collect this fee without

distinct from) the deduction from the loss against income abuse may be a problem. In addition, the procedure may

that a utility takes as a result of writing down generating introduce new unacceptable barriers to entry.

assets.

Other Options 

These are strategies that cannot be conveniently

categorized elsewhere. As usual, most of these strategies

originated in suggestions for offsetting strandable costs.

Preserve Retail Franchise: Preservation of retail franchise

is recommended as an option because delaying compeEliminate Obligation To Serve: In the absence of

Statutorily Authorized Recovery: It is possible to enact

278

Entrance Fee for New Generation: New generation
150 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 The ORFIN is an integrated utility planning model developed at the Oak Ridge National Laboratory. Model characteristics are briefly described in 279

Appendix D. For additional details with respect to the ORFIN model, refer to Oak Ridge National Laboratory, ORFIN: An Electric Financial and Production

Simulator, ORNL/CON-430 (Oak Ridge, TN, March 1996). The authors of the study (from which this summary has been adapted) prefer to use the term

“transition costs,” which is used synonymously with “stranded costs” or “strandable costs” in this report.

 The term “wheeling” implies moving electric power from one system to another over the transmission facilities of the intervening systems. Within 280

the context of industry restructuring, wholesale or retail buyers of electricity have the freedom to select a supplier of their choice. Wholesale wheeling indicates

bulk transactions in the wholesale market, whereas retail wheeling allows producers direct access to retail customers.

 Estimating the impact of some strategies by keeping the retail prices constant is not always feasible. Strategies that involve a reduction in public policy 281

programs may be permissible only in conjunction with a change in rates. In such a case, the approach used is to define a revised base case that include

changes to the utility's cost structure as a result of the strategy adopted and then to estimate its impact on strandable costs.

 It is emphasized that the results presented are with reference to the specifics of the base case utility only. Any attempt to generalize these conclusions 282

would, therefore, be inappropriate.

Who Bears Transition Costs?

Most strategies identified above would shift costs among

different segments of the economy (e.g., from shareholders to ratepayers, taxpayers, other independent

power producers, or the State and Federal Government)

either immediately or over a period of time. As an

example, shareholders of a utility with above-market

generating costs will stand to suffer significant losses in

the event that retail markets are opened rapidly, assuming

that no other actions are taken either by the utility or the

regulators. In contrast, utility cost reduction measures or

implementation of efficiency improvements would lower

potential stranded costs without any cost shifting.

Most mitigation strategies, however, involve a shifting or

sharing of the costs by different economic segments (Table

E2). These strategies are, however, broad based with the

result that the sphere of operational accountability is

enlarged to encompass all classes of participants,

including utilities' shareholders, ratepayers, taxpayers,

wheeling customers, and others. Whether one or more

economic agent will bear the costs that a utility can no

longer recover in a competitive environment (and are thus

stranded) is determined by selection of a strategy for

implementation.

Of the strategies discussed above, a qualitative assessment

shows that ratepayers have the primary or secondary

responsibility for absorbing the stranded costs in 19

strategies, shareholders in 12, wheeling customers in 11,

taxpayers in 8, and nonutility suppliers in 4 strategies

(Table E2). Not all the strategies can be applied in a way

to determine their impact (i.e., who pays stranded/

strandable costs) with neat precision. 

As an example, depreciation reserves may be transferred

among assets in an attempt to make generating assets less

vulnerable (to competition) but only if bundled services

continue to be provided. If rates are unbundled, costs

would need to be shifted among the ratepayers and the

wheeling customers. The tax consequences of the various

strategies (such as revenue losses experienced by utilities

or the writedown of assets) are not fully examined because of the inherent difficulties involved. A divestiture,

in the absence of any countervailing action(s), will leave

the onus on shareholders and the taxpayers in the event of

a financial loss. It may also have significant impacts on

local government finances. 

Quantitative Assessment of Different

Strategies

The Oak Ridge Financial Model (ORFIN) was used to

assess the effects of selected mitigation strategies on the

level of potential stranded costs. This model is a simpli- 279

fied version of a utility integrated planning model and includes a production-costing module, utility financial statements (income statement, balance sheet, and cash-flow

statement), and a rate-design module (functionalization,

classification, and allocation of costs to customer classes).

The estimation is based on the following three-step

procedure:

 A base case utility is defined.

 A retail wheeling scenario (in which retail

customers have the choice to select an alternative

supplier) is created to estimate its consequences

on the utility shareholders under assumptions of

constant retail prices.280

 A mitigation strategy is incorporated to estimate

its financial impact in comparison with the

previous step.281

Table E3 summarizes the results of the different strategies

and places them into large, medium, and modest impact

categories. Their potential effects are compared with the

base case utility's strandable costs. Since the absolute 282

effects of different strategies are contingent on the

assumptions made in creating the base case, Table E3
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 151

Table E2. Who Bears Transition Costs?

Strategy Shareholders Ratepayers Taxpayers Customers QFs, IPPs

Utility Wheeling

Market Actions

Open markets . . . . . . . . . . . . . . . . . . . . . . P -- S -- S

Delay competition . . . . . . . . . . . . . . . . . . . -- P -- -- --

Divest utility plant . . . . . . . . . . . . . . . . . . . . P -- S -- --

Mergers .......................... a -- -- -- -- --

Market excess power . . . . . . . . . . . . . . . . P P -- -- --

Depreciation Options

Accelerate depreciation . . . . . . . . . . . . . . -- P -- -- --

Accelerate/decelerate depreciation . . . . . -- P -- -- --

Transfer depreciation reserves . . . . . . . . . -- P -- S --

Economic levelization . . . . . . . . . . . . . . . . -- P -- -- --

Ratemaking Actions

Adjust utility returns . . . . . . . . . . . . . . . . . P S -- --

Eliminate subsidies . . . . . . . . . . . . . . . . . . -- P -- -- --

Restructure rates . . . . . . . . . . . . . . . . . . . . -- P -- -- --

Unbundle rates . . . . . . . . . . . . . . . . . . . . . -- P -- S --

Allow rate flexibility . . . . . . . . . . . . . . . . . . -- P -- -- --

Performance-based rates . . . . . . . . . . . . . P S -- --

Disallow costs . . . . . . . . . . . . . . . . . . . . . . P -- S -- --

Explicitly shift costs to captive customers -- P -- -- --

Exit fees . . . . . . . . . . . . . . . . . . . . . . . . . . . -- -- -- P --

Net generation savings . . . . . . . . . . . . . . . P -- -- P --

Access charges . . . . . . . . . . . . . . . . . . . . . -- P -- P --

Utility Cost Reductions

Reduce operating costs . . . . . . . . . . . . . . P P -- -- --

Reduce public policy program costs .... b -- -- -- -- --

Reduce power purchase costs . . . . . . . . . P -- -- -- P

Financial writedowns . . . . . . . . . . . . . . . . . P -- S -- --

Tax Measures

Consumption tax . . . . . . . . . . . . . . . . . . . . -- P -- P --

National tax for nuclear plants . . . . . . . . . -- P -- P --

Production tax . . . . . . . . . . . . . . . . . . . . . . S P -- P S

Tax reduction . . . . . . . . . . . . . . . . . . . . . . -- -- P -- --

Tax deduction . . . . . . . . . . . . . . . . . . . . . . -- -- P -- --

Other Options

Preserve retail franchise . . . . . . . . . . . . . . -- P -- -- --

Eliminate obligation to serve . . . . . . . . . . . P -- S -- --

Statutorily authorized recovery . . . . . . . . . -- P -- P --

Entrance fee for returning customers . . . . -- -- -- P --

Entrance fee for new generation . . . . . . . -- -- -- S P

 Assessing the effects mergers will have on transition costs is beyond the concept of the ORFIN model. a

 Reductions in public policy program costs reflect reductions in services. Prospective program participants and society in general b

will bear the transition costs.

 IPP = Independent power producer.

 P = Actor with primary responsibility.

 QF = Qualifying facility.

 S = Actor with secondary responsibility.

 -- = Not applicable.

 Source: Oak Ridge National Laboratory, Strategies to Address Transition Costs in the Electricity Industry, ORNL/CON-431 (Oak

Ridge, TN, July 1996).
152 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Table E3. Potential Effects of Different Strategies on Base-Case Utility Transition Costs

Potential Effect on

Utility Transition Costs Strategya

Financial Impacts

(Million Dollars)

Increase Decrease

Large (25 percent or greater)... Rapidly open retail markets (+) 2,361 (+96.0)

Delay retail wheeling (-) -788 (-32.2)

Market excess energy (±) 662 (+27.0) -111 (-4.5)

Charge exit fees (-) -2,363 (-96.5)

Reduce administrative and general costs (-) -1,049 (-42.8)

Discount qualifying facility energy payments -2,481 (-101.3)

to market (-)

Medium (between 5 and 25

 percent) ................... Increase system load factors (±)

208 (+8.5) -165 (-6.7)

Accelerate depreciation of the generation 119 (+4.9)

plant (+)

Charge wheeling customers for ancillary -240 (-9.8)

services (-)

Reduce customer-service costs (-) -381 (-15.6)

Reduce transmission operating and -194 (-7.9)

maintenance costs (-)

Reduce distribution operating and -246 (-10.0)

maintenance costs (-)

Reduce generation operating and -467 (-19.1)

maintenance costs (-)

Discount qualifying facility capacity payments -410 (-16.7)

to market (-)

Modest (less than 5 percent) ... Accelerate depreciation of the generation 49 (+2.0)

plant and decelerate depreciation of the

transmission and distribution plant (+)

Accelerate depreciation of regulatory assets 77 (+3.1) -38 (-1.6)

(±)

Reduce public policy program costs (-) -23 (-1.0)

 A “(+)” indicates the strategy increases transition costs; a “(-)” indicates the strategy decreases transition costs; a “(±)” indicates the a

strategy may increase or decrease transition costs.

 Note: The numbers in parentheses reflect increases or decreases as a percentage of the total stranded costs of the hypothetical

utility.

 Source: Oak Ridge National Laboratory, Strategies to Address Transition Costs in the Electricity Industry, ORNL/CON-431 (Oak

Ridge, TN, July 1996).
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 153

 U. S. Department of Energy, The Electric Power Outages in the Western United States, July 2-3, 1996: Report to the President (Washington, DC, 283

August 1996).

provides a general indication of how the strategy might

work in similar applications comparable to the base case.

However, not all utilities may have the potential for

stranded costs, and the potentially affected utilities will

have above-market costs in at least one of three areas:

utility-owned generation, power purchase contracts, and

regulatory assets.

Several of the mitigation strategies can potentially reduce

the magnitude of a utility's strandable costs. However, a

number of strategies require regulatory approval for implementation, particularly, exit fees and depreciation

options.

Utility cost reduction strategies have a significant appeal

because most of them can be initiated by the utilities

themselves with positive results in lowering strandable

costs. A number of utilities have already embarked on

such programs with encouraging results. The danger in

this situation results from going too far, so that essential

maintenance activities may be stretched out with

unacceptable consequences. In the midst of changes that

are now occurring in the electric utility industry,

maintaining the reliability of the Nation's bulk electric

systems poses new challenges.283

A resolution of who pays stranded costs will have a major

impact upon, but will not be the sole issue that determines, the speed at which transition of the industry to a

competitive mode is accomplished. While FERC Order

888 clearly places the onus of stranded cost recovery on

the backs of departing customers, there are no clear

signals with respect to recovery of similar costs in the area

of retail trade, due to the lack of a uniform approach

among State regulatory authorities. Many States are still

grappling with this issue.

The results presented above must be interpreted with

caution. Utility cost structures differ in critical areas that

render interutility comparisons without further investigation inappropriate. Generally, these differences account

for whether a utility is a high-cost or a low-cost producer.

Thus, the results of a strategy application are difficult to

generalize, but they may indicate that a case-by-case

investigation would be useful in determining the efficacy

of the strategy.

A more detailed explanation of the three-step estimation

procedure follows.

Base Case

The construct of a hypothetical base case utility is based

on selecting a utility that potentially faces substantial

transition (or strandable) costs. Data for the 1994-1995

period are used. The intent is not to simulate any

particular utility's performance nor that of the whole

industry, but rather to make the assessments consistent

with actual data.

Following are the characteristics of the base case utility: 

Rate base: $7.3 billion

Common equity: $3.2 billion

Revenues: $4.6 billion

Annual retail sales: 43,800 gigawatthours

Total generating capacity: 10,000 megawatts

Utility-owned capacity: 5,200 megawatts

Long-term purchase contracts: 4,800 megawatts

Retail peak demand: 7,500 megawatts

Long-term power purchase contracts are in effect through

the 10-year analysis period. The utility's total capacity of

10,000 megawatts consists of 13 percent nuclear, 16

percent coal, 8 percent natural gas, 7 percent hydroelectric, 8 percent oil, 17 percent hydroelectric purchases,

and 31 percent purchases from QFs. Note that nearly 90

percent of the QF contracts (about 2,800 megawatts) have

“must run” provisions, which imply that the utility must

purchase the power when it is available. The combined

capacity and energy payments for these must-run

contracts are about 7.2 cents per kilowatthour.

The utility's large coal plant (1,570 megawatts), one of its

natural gas plants, and all of its hydroelectric plants are

fully depreciated. Its nuclear plant will be fully depreciated in 2018. The utility's regulatory assets are about

$1.0 billion. The utility's annual sales and peak demand

grow by about 1.0 percent each year (assuming the

absence of retail wheeling). Its system load factor is 66

percent. 

The utility is active in the wholesale market given its

surplus capacity, transmission links, and low marginal

generation costs of about 2.1 cents per kilowatthour. Its

wholesale sales, which are about 9,400 gigawatthours, are

projected to decline by about 4 percent annually into the

future. Its purchases of about 1,000 gigawatthours are

projected to increase by about 9 percent annually. The 
154 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

 In establishing benchmarks for various cost categories, all medium to large-sized electric utilities were selected from a database that contains all U.S. 284

electric utilities. Using the subset so derived, the frequency distribution of each cost variable was examined. Its mean, median, standard deviation and

resulting frequency distribution were then estimated. For each cost distribution, its 90th percentile value was estimated after accounting for various other

factors that might bias the selection process. For additional details, refer to Oak Ridge National Laboratory, Strategies to Address Transition Costs in the

Electricity Industry, ORNL/CON-431 (Oak Ridge, TN, July 1996).

utility is assumed to be a “price-taker” in the market—i.e., The results of the hypothesized wheeling experiment

its purchases or sales have no effect on market prices. show a decline in utility retail sales by 24,700 gigawattIn estimating rates for each customer class for the base Wholesale purchases by the utility are eliminated and are

case, the utility's revenue requirements include all its costs replaced by a significant increase in wholesale sales. The

and an authorized rate of return of 11 percent on its utility's per-unit production costs increase since costs are

equity. The hypothetical utility’s customer rates are well spread over a declining customer base. Net income losses

above the national average. amount to $137 million in 1996, peaking at $527 million in

With inflation assumed to average 3 percent annually, the The net present value of aggregate losses, or the transition

real discount rate works out to be 8 percent. With cost, is $2.45 billion, representing about 77 percent of the

assumptions of no real increases in fuel prices and no new firm's 1995 equity of $3.2 billion.

generating units (but new investments in transmission

and distribution facilities), the base case utility's

projections (for selected variables and with no retail

wheeling) for the period 1995 through 2005 are shown in

Table E4.

Retail Wheeling Case

The retail wheeling case assumes that wheeling starts in

1996 for commercial and industrial customers, with the

result that 60 percent of them have alternative suppliers

by 1998. Residential customers commence wheeling in

1997, and 40 percent of them secure supplies from

alternative sources by 2000. These percentages are kept

constant, and the impact of the changes on the base case

utility is evaluated.

hours (or by about 54 percent) by the year 2000 (Table E5).

2000 before declining graduallyto $510 million by 2005.

Assessing Impacts of Selected Mitigation

Strategies

To eliminate the need to make arbitrary assumptions

about the utility's cost variables, performance benchmarks

were established for designated areas of operation. These

include administrative and general expenses, customer

services, transmission and distribution, and operations

and management expenses. In addition, benchmarks for

fixed and variable costs of various generating plants (by

fuel type) were also established by using a statistical

technique (Table E6). 284
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 155

Table E4. Base Case Utility Projections (No Wheeling)

1995 1996 1997 1998 1999 2000 2005

Annual Summary

 Retail Sales (GWh) at Busbar ....... 43,809 44,274 44,744 45,220 45,700 46,187 48,700

 Wholesale (spot) Sales (GWh) ...... 9,424 9,070 8,713 8,361 8,012 7,666 5,992

 Wholesale (spot) Purchases (GWh) . . -1,020 -1,129 -1,242 -1,364 -1,494 -1,634 -2,471

 Net Wholesale GWh .............. 8,404 7,940 7,471 6,997 6,517 6,033 3,521

 Retail Wheeling .................. 0 0 0 0000

Peak Demand at Busbar (MW)

 Retail .......................... 7,522 7,603 7,685 7,768 7,852 7,937 8,376

 Wholesale Sales ................. 1,941 1,897 1,853 1,810 1,766 1,722 1,493

 Wholesale Purchases . . . . . . . . . . . . . 680 707 721 742 770 801 906

 Retail Wheeling .................. 0 0 0 0000

Costs and Prices (1994 ¢/kWh)

 Average Retail Price .............. 10.98 10.76 10.54 10.33 10.14 9.95 9.19

 Average Production Costs

 Fixed ......................... 2.82 2.64 2.46 2.30 2.14 2.00 1.44

 Variable ....................... 2.82 2.81 2.81 2.80 2.80 2.79 2.76

 Total .......................... 5.64 5.45 5.27 5.10 4.94 4.79 4.20

Return on Equity (Percent) .......... 11.00 11.00 11.00 11.00 11.00 11.00 11.00

Income Statement (million nominal

 dollars)

Revenues ........................ 4,615 4,705 4,799 4,898 5,001 5,110 5,767

Expenses

 Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 287 295 304 313 323 332 385

 Purchase-Power Constraints ...... 1,405 1,438 1,473 1,508 1,545 1,583 1,789

 Spot Purchases . . . . . . . . . . . . . . . . . 36 41 45 50 56 62 102

 Spot Sales ..................... -196 -194 -191 -189 -186 -183 -164

 Purchases Power - Total ........... 1,245 1,285 1,326 1,370 1,415 1,462 1,726

 O&M, Fixed + Variable . . . . . . . . . . . . . 254 262 270 278 286 295 342

Production Expenses – Total ........ 1,786 1,842 1,900 1,961 2,023 2,089 2,453

Nonproduction Expenses . . . . . . . . . . . 854 884 914 946 978 1,012 1,199

Book Depreciation . . . . . . . . . . . . . . . . . 231 235 240 245 251 256 283

Depreciation of Regulatory Asset . . . . . 91 91 91 91 91 91 91

Revenue Sensitive Taxes . . . . . . . . . . . 462 470 480 490 500 511 577

Property Taxes . . . . . . . . . . . . . . . . . . . 317 319 322 325 328 331 350

Federal Income Taxes – Current . . . . . 201 197 193 189 186 185 265

Federal Income Taxes – Deferred . . . . 35 35 35 35 35 33 -49

Expenses – Total .................. 3,977 4,074 4,176 4,281 4,392 4,507 5,169

Interest Expense . . . . . . . . . . . . . . . . . . 284 282 281 280 278 277 275

Net Income . . . . . . . . . . . . . . . . . . . . . . 355 349 343 337 331 326 323

BALANCE SHEET

Assets .......................... 7,269 7,229 7,192 7,160 7,132 7,107 7,053

Equity ........................... 3,196 3,141 3,088 3,036 2,987 2,942 2,963

 Source: Oak Ridge National Laboratory, Strategies to Address Transition Costs in the Electricity Industry, ORNL/CON-431

(Oak Ridge, TN, July 1996).
156 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Table E5. Base Case Utility Projections (With Wheeling)

1995 1996 1997 1998 1999 2000 2005

Annual Summary

 Retail Sales (GWh) at Busbar ..... 0 -6,036 -13,611 -21,335 -23,012 -24,732 -26,024

 Wholesale (spot) Sales (GWh) .... 0 5,080 12,265 18,965 20,341 21,505 22,372

 Wholesale (spot) Purchases (GWh) 0 898 1,237 1,364 1,494 1,634 2,471

 Net Wholesale GWh ............ 0 5,978 13,502 20,329 21,835 23,139 24,843

 Retail Wheeling ................ 0 6,036 13,611 21,335 23,012 24,732 26,024

Peak Demand at Busbar (MW)

 Retail ........................ 0 -984 -2,258 -3,558 -3,873 -4,195 -4,418

 Wholesale Sales . . . . . . . . . . . . . . . 0 578 1,249 1,701 1,821 1,907 2,094

 Wholesale Purchasing .......... 0 -468 -711 -742 -770 -801 -906

 Retail Wheeling . . . . . . . . . . . . . . . . 0 984 2,258 3,558 3,873 4,195 4,418

Costs and Prices (1994 ¢/kWh)

 Average Retail Price ............ 0 0.19 0.34 0.60 0.48 0.34 0.32

 Average Production Costs

 Fixed ....................... 0 0.42 1.08 2.05 2.17 2.30 1.65

 Variable ..................... 0 0.07 0.20 0.43 0.48 0.56 0.52

 Total ........................ 0 0.49 1.27 2.48 2.66 2.86 2.17

Return on Equity (Percent) ........ 0 -4.33 -9.22 -14.72 -16.20 -17.79 -17.37

Income Statement (million nominal

 dollars)

Revenues ...................... 0 -422 -921 -1,453 -1,591 -1,734 -1,870

Expenses

 Fuel . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 0 -9 -13 -19 -15

 Purchase-Power Constraints . . . . 0 -4 -7 -8 -8 -8 -10

 Spot Purchases . . . . . . . . . . . . . . . 0 -31 -45 -50 -56 -62 -102

 Spot Sales ................... 0 -116 -299 -489 -540 -590 -704

 Purchases Power - Total ......... 0 -151 -350 -546 -604 -660 -815

 O&M, Fixed + Variable . . . . . . . . . . . 0 0 0 -1 -2 -2 -2

Production Expenses – Total ...... 0 -151 -350 -557 -618 -681 -832

Nonproduction Expenses ......... 0 0 0 0 0 0 0

Book Depreciation ............... 0 0 0 0 0 0 0

Depreciation of Regulatory Asset . . . 0 0 0 0 0 0 0

Revenue Sensitive Taxes . . . . . . . . . 0 -42 -92 -145 -159 -173 -187

Property Taxes ................. 0 0 0 0 0 0 0

Federal Income Taxes – Current . . . 0 -92 -191 -300 -325 -352 -340

Federal Income Taxes – Deferred . . 0 0 0 0 0 0 0

Expenses – Total ................ 0 -284 -634 -1,003 -1,103 -1,206 -1,359

Interest Expense ................ 0 0 0 0 0 0 0

Net Income .................... 0 -137 -287 -451 -488 -527 -510

BALANCE SHEET

Assets ........................ 0 0 0 0 0 0 0

Equity ......................... 0 0 0 0 0 0 0

Note: The numbers in each column are derived by subtracting the “Base Case Utility Projections” from projections of the base case

with assumptions regarding wheeling.

Source: Oak Ridge National Laboratory, Strategies to Address Transition Costs in the Electricity Industry, ORNL/CON-431 (Oak

Ridge, TN, July 1996).
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 157

Table E6. Performance Benchmark for Utility Cost Variables

Cost Variable Base Case Value Industry Average Benchmark

Performance

Administrative & General (dollars/customer) . . . . . . . . . . . . 231 156 96

Customer Service (dollars/customer) . . . . . . . . . . . . . . . . . . 92 63 45

Administrative & General, Customer Service ...........

 Combined (dollars/customer) . . . . . . . . . . . . . . . . . . . . . . . 323 219 154

Transmission Operations and Maintenance (dollars/kW-yr) 8 4 2

Distribution Operations and Maintenance (dollars/kW-yr) . 20 12 8

Plant Operations and Maintenance

 Nuclear

 Fixed (dollars/kW-yr) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125 91 61

 Variable (cents/kWh) ............................. 0.06 0.04 0.03

 Coal

 Fixed (dollars/kW-yr) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 26 12

 Variable (cents/kWh) ............................. 0.16 0.18 0.08

 Natural Gas 1

 Fixed (dollars/kW-yr) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 24 8

 Variable (cents/kWh) ............................. 0.09 0.10 0.03

 Oil

 Fixed (dollars/kW-yr) ............................. 6 7 2

 Variable (cents/kWh) ............................. 0.11 0.13 0.03

 Hydro

 Fixed (dollars/kW-yr) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 12 3

 Variable (cents/kWh) ............................. 0.08 0.24 0.06

 kW = Kilowatt.

 kWh = Kilowatthour.

 Source: Oak Ridge National Laboratory, Strategies to Address Transition Costs in the Electricity Industry, ORNL/CON-431 (Oak

Ridge, TN, July 1996).
Appendix F

Selected Provisions 

of the Energy Policy

Act of 1992 

(Public Law 102-486),

Title VII—Electricity
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 161

Appendix F

Selected Provisions of the Energy Policy Act of 1992

(Public Law 102-486), Title VII—Electricity

Subtitle A—Exempt Wholesale Generators

15 USC 79, amended by redesignating sections 32 and 33 as sections 34 and 35 respectively and by adding the following

79z-6. new section after section 31: 

15 USC 79z-5a.

Regulations makes such determination. The Federal Energy Regulatory Commission shall make such

SEC. 711. PUBLIC UTILITY HOLDING COMPANY ACT REFORM.

The Public Utility Holding Company Act of 1935 (15 U.S.C. 79 and following) is

“SEC. 32. EXEMPT WHOLESALE GENERATORS.

“(a) DEFINITIONS.—For purposes of this section—

“(1) EXEMPT WHOLESALE GENERATOR.—The term 'exempt wholesale generator' means any

person determined by the Federal Energy Regulatory Commission to be engaged directly, or

indirectly through one or more affiliates as defined in section 2(a)(11)(b), and exclusively in the

business of owning or operating, or both owning and operating, all or part of one or more eligible

facilities and selling electric energy at wholesale. No person shall be deemed to be an exempt

wholesale generator under this section unless such person has applied to the Federal Energy

Regulatory Commission for a determination under this paragraph. A person applying in good faith

for such a determination shall be deemed an exempt wholesale generator under this section, with

all of the exemptions provided by this section, until the Federal Energy Regulatory Commission

determination within 60 days of its receipt of such application and shall notify the Commission

whenever a determination is made under this paragraph that any person is an exempt wholesale

generator. Not later than 12 months after the date of enactment of this section, the Federal Energy

Regulatory Commission shall promulgate rules implementing the provisions of this paragraph.

Applications for determination filed after the effective date of such rules shall be subject thereto.

“(2) ELIGIBLE FACILITY.—The term 'eligible facility' means a facility, wherever located, which

is either—

“(A) used for the generation of electric energy exclusively for sale at wholesale, or

“(B) used for the generation of electric energy and leased to one or more public utility

companies; Provided, That any such lease shall be treated as a sale of electric energy at wholesale

for purposes of sections 205 and 206 of the Federal Power Act.

Such term shall not include any facility for which consent is required under subsection (c) if such

consent has not been obtained. Such term includes interconnecting transmission facilities necessary

to effect a sale of electric energy at wholesale. For purposes of this paragraph the term 'facility' may

include a portion of a facility subject to the limitations of subsection (d) and shall include a facility

the construction of which has not been commenced or completed.

“(3) SALE OF ELECTRIC ENERGY AT WHOLESALE.—The term 'sale of electric energy at

wholesale' shall have the same meaning as provided in section 201(d) of the Federal Power Act (16

U.S.C. 824(d)).
162 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

“(4) RETAIL RATES AND CHARGES.—The term 'retail rates and charges' means rates and charges for the

sale of electric energy directly to consumers.

“(b) FOREIGN RETAIL SALES.—Notwithstanding paragraphs (1) and (2) of subsection (a), retail

sales of electric energy produced by a facility located in a foreign country shall not prevent such facility from

being an eligible facility, or prevent a person owning or operating, or both owning and operating, such facility

from being an exempt wholesale generator if none of the electric energy generated by such facility is sold to

consumers in the United States. 

“(c) STATE CONSENT FOR EXISTING RATE-BASED FACILITIES.— If a rate or charge for, or in

connection with, the construction of a facility, or for electric energy produced by a facility (other than any

portion of a rate or charge which represents recovery of the cost of a wholesale rate or charge) was in effect

under the laws of any State as of the date of enactment of this section, in order for the facility to be considered

an eligible facility, every State commission having jurisdiction over any such rate or charge must make a

specific determination that allowing such facility to be an eligible facility (1) will benefit consumers, (2) is in

the public interest, and (3) does not violate State law; Provided, That in the case of such a rate or charge which

is a rate or charge of an affiliate of a registered holding company:

“(A) such determination with respect to the facility in question shall be required from every State

commission having jurisdiction over the retail rates and charges of the affiliates of such registered

holding company; and 

“(B) the approval of the Commission under this Act shall not be required for the transfer of the

facility to an exempt wholesale generator.

“(d) HYBRIDS.—(1) No exempt wholesale generator may own or operate a portion of any facility

if any other portion of the facility is owned or operated by an electric utility company that is an affiliate or

associate company of such exempt wholesale generator.

“(2) ELIGIBLE FACILITY.—Notwithstanding paragraph (1), an exempt wholesale generator may

own or operate a portion of a facility identified in paragraph (1) if such portion has become an eligible facility

as a result of the operation of subsection (c).

“(e) EXEMPTION OF EWGS.—An exempt wholesale generator shall not be considered an electric

utility company under section 2(a)(3) of this Act and, whether or not a subsidiary company, an affiliate, or

an associate company of a holding company, an exempt wholesale generator shall be exempt from all

provisions of this Act.

“(f) OWNERSHIP OF EWGS BY EXEMPT HOLDING COMPANIES.— Notwithstanding any

provision of this Act, a holding company that is exempt under section 3 of this Act shall be permitted, without

condition or limitation under this Act, to acquire and maintain an interest in the business of one or more

exempt wholesale generators.

“(g) OWNERSHIP OF EWGS BY REGISTERED HOLDING COMPANIES.— Notwithstanding any

provision of this Act and the Commission's jurisdiction as provided under subsection (h) of this section, a

registered holding company shall be permitted (without the need to apply for, or receive, approval from the

Commission, and otherwise without condition under this Act) to acquire and hold the securities, or an interest

in the business, of one or more exempt wholesale generators.

“(h) FINANCING AND OTHER RELATIONSHIPS BETWEEN EWGS AND REGISTERED

HOLDING COMPANIES.—The issuance of securities by a registered holding company for purposes of

financing the acquisition of an exempt wholesale generator, the guarantee of securities of an exempt

wholesale generator by a registered holding company, the entering into service, sales or construction

contracts, and the creation or maintenance of any other relationship in addition to that described in subsection

(g) between an exempt wholesale generator and a registered holding company, its affiliates and associate

companies, shall remain subject to the jurisdiction of the Commission under this Act: Provided, That—

“(1) section 11 of this Act shall not prohibit the ownership of an interest in the business of one

or more exempt wholesale generators by a registered holding company (regardless of where

facilities owned or operated by such exempt wholesale generators are located), and such ownership

by a registered holding company shall be deemed consistent with the operation of an integrated

public utility system;
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 163

“(2) the ownership of an interest in the business of one or more exempt wholesale generators by

a registered holding company (regardless of where facilities owned or operated by such exempt

wholesale generators are located) shall be considered as reasonably incidental, or economically

necessary or appropriate, to the operations of an integrated public utility system;

“(3) in determining whether to approve (A) the issue or sale of a security by a registered holding

company for purposes of financing the acquisition of an exempt wholesale generator, or (B) the

guarantee of a security of an exempt wholesale generator by a registered holding company, the

Commission shall not make a finding that such security is not reasonably adapted to the earning

power of such company or to the security structure of such company and other companies in the

same holding company system, or that the circumstances are such as to constitute the making of such

guarantee an improper risk for such company, unless the Commission first finds that the issue or sale

of such security, or the making of the guarantee, would have a substantial adverse impact on the

financial integrity of the registered holding company system;

“(4) in determining whether to approve (A) the issue or sale of a security by a registered holding

company for purposes other than the acquisition of an exempt wholesale generator or (B) other

transactions by such registered holding company or by its subsidiaries other than with respect to

exempt wholesale generators, the Commission shall not consider the effect of the capitalization or

earnings of any subsidiary which is an exempt wholesale generator upon the registered holding

company system, unless the approval of the issue or sale or other transaction, together with the effect

of such capitalization and earnings, would have a substantial adverse impact on the financial

integrity of the registered holding company system;

“(5) the Commission shall make its decision under paragraph (3) to approve or disapprove the

issue or sale of a security or the guarantee of a security within 120 days of the filing of a declaration

concerning such issue, sale or guarantee; and

“(6) the Commission shall promulgate regulations with respect to the actions which would be

considered, for purposes of this subsection, to have a substantial adverse impact on the financial

integrity of the registered holding company system; such regulations shall ensure that the action has

no adverse impact on any utility subsidiary or its customers, or on the ability of State commissions

to protect such subsidiary or customers, and shall take into account the amount and type of capital

invested in exempt wholesale generators, the ratio of such capital to the total capital invested in

utility operations, the availability of books and records, and the financial and operating experience

of the registered holding company and the exempt wholesale generator; the Commission shall

promulgate such regulations within 6 months after the enactment of this section, after such 6-month

period the Commission shall not approve any actions under paragraph (3), (4) or (5) except in

accordance with such issued regulations.

“(I) APPLICATION OF ACT TO OTHER ELIGIBLE FACILITIES.—In the case of any person engaged

directly and exclusively in the business of owning or operating (or both owning and operating) all or part of

one or more eligible facilities, an advisory letter issued by the Commission staff under this Act after the date

of enactment of this section, or an order issued by the Commission under this Act after the date of enactment

of this section, shall not be required for the purpose, or have the effect, of exempting such person from

treatment as an electric utility company under section 2(a)(3) or exempting such person from any provision

of this Act.

“(j) OWNERSHIP OF EXEMPT WHOLESALE GENERATORS AND QUALIFYING

FACILITIES.—The ownership by a person of one or more exempt wholesale generators shall not result in such

person being considered as being primarily engaged in the generation or sale of electric power within the

meaning of sections 3(17)(C)(ii) and 3(18)(B)(ii) of the Federal Power Act (16 U.S.C. 796(17)(C)(ii) and

796(18)(B)(ii)).

“(k) PROTECTION AGAINST ABUSIVE AFFILIATE TRANSACTIONS.— “(1)

PROHIBITION.—After the date of enactment of this section, an electric utility company may not enter into a

contract to purchase electric energy at wholesale from an exempt wholesale generator if the exempt wholesale

generator is an affiliate or associate company of the electric utility company.

“(2) STATE AUTHORITY TO EXEMPT FROM PROHIBITION.—Notwithstanding paragraph

(1), an electric utility company may enter into a contract to purchase electric energy at wholesale

from an exempt wholesale generator that is an affiliate or associate company of the electric utility

company—

“(A) if every State commission having jurisdiction over the retail rates of such electric

utility company makes each of the following specific determinations in advance of the

electric utility company entering into such contract: 

“(i) A determination that such commission has sufficient regulatory authority,

resources and access to books and records of the electric utility company and any

relevant associate, affiliate or subsidiary company to exercise its duties under this

subparagraph.
164 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

“(ii) A determination that the transaction—

“(I) will benefit consumers,

“(II) does not violate any State law (including where applicable, least

cost planning),

“(III) would not provide the exempt wholesale generator any unfair

competitive advantage by virtue of its affiliation or association with the electric

utility company, and

“(IV) is in the public interest; or 

“(B) if such electric utility company is not subject to State commission retail rate

regulation and the purchased electric energy:

“(i) would not be resold to any affiliate or associate company, or

“(ii) the purchased electric energy would be resold to an affiliate or associate

company and every State commission having jurisdiction over the retail rates of such

affiliate or associate company makes each of the determinations provided under

subparagraph (A), including the determination concerning a State commission's

duties. 

“(l) RECIPROCAL ARRANGEMENTS PROHIBITED.—Reciprocal arrangements among companies

that are not affiliates or associate companies of each other that are entered into in order to avoid the

provisions of this section are prohibited.”.

SEC. 712. STATE CONSIDERATION OF THE EFFECTS OF POWER PURCHASES ON

UTILITY COST OF CAPITAL; CONSIDERATION OF THE EFFECTS OF LEVERAGED

CAPITAL STRUCTURES ON THE RELIABILITY OF WHOLESALE POWER SELLERS; AND

CONSIDERATION OF ADEQUATE FUEL SUPPLIES.

Section 111 of the Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 2601 and following) is amended by

inserting the following new paragraph after paragraph (9):

“(10) CONSIDERATION OF THE EFFECTS OF WHOLESALE POWER PURCHASES ON

UTILITY COST OF CAPITAL; EFFECTS OF LEVERAGED CAPITAL STRUCTURES ON THE

RELIABILITY OF WHOLESALE POWER SELLERS; AND ASSURANCE OF ADEQUATE FUEL

SUPPLIES.—(A) To the extent that a State regulatory authority requires or allows electric utilities

for which it has ratemaking authority to consider the purchase of long-term wholesale power

supplies as a means of meeting electric demand, such authority shall perform a general evaluation

of:

“(i) the potential for increases or decreases in the costs of capital for such utilities, and any

resulting increases or decreases in the retail rates paid by electric consumers, that may result

from purchases of long-term wholesale power supplies in lieu of the construction of new

generation facilities by such utilities; 16 USC 2621.

“(ii) whether the use by exempt wholesale generators (as defined in section 32 of the Public

Utility Holding Company Act of 1935) of capital structures which employ proportionally greater

amounts of debt than the capital structures of such utilities
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 165

15 USC 79k retain, in any geographic area, an interest in any qualifying cogeneration facilities and qualifying small power

note. production facilities as defined pursuant to the Public Utility Regulatory Policies Act of 1978, and shall qualify

16 USC 824. “(g) BOOKS AND RECORDS.—(1) Upon written order of a State commission, a State commission

threatens reliability or provides an unfair advantage for exempt wholesale generators over such

utilities;

“(iii) whether to implement procedures for the advance approval or disapproval of the purchase

of a particular long-term wholesale power supply; and

“(iv) whether to require as a condition for the approval of the purchase of power that there be

reasonable assurances of fuel supply adequacy.

“(B) For purposes of implementing the provisions of this paragraph, any reference contained in this

section to the date of enactment of the Public Utility Regulatory Policies Act of 1978 shall be deemed to be a

reference to the date of enactment of this paragraph.

“(C) Notwithstanding any other provision of Federal law, nothing in this paragraph shall prevent

a State regulatory authority from taking such action, including action with respect to the allowable capital

structure of exempt wholesale generators, as such State regulatory authority may determine to be in the public

interest as a result of performing evaluations under the standards of subparagraph (A).

“(D) Notwithstanding section 124 and paragraphs (1) and (2) of section 112(a), each State regulatory

authority shall consider and make a determination concerning the standards of subparagraph (A) in

accordance with the requirements of subsections (a) and (b) of this section, without regard to any proceedings

commenced prior to the enactment of this paragraph.

“(E) Notwithstanding subsections (b) and (c) of section 112, each State regulatory authority shall

consider and make a determination concerning whether it is appropriate to implement the standards set out

in subparagraph (A) not later than one year after the date of enactment of this paragraph.”.

SEC. 713. PUBLIC UTILITY HOLDING COMPANIES TO OWN INTERESTS IN

COGENERATION FACILITIES. 

Public Law 99-186 (99 Stat. 1180, as amended by Public Law 99-553, 100 Stat. 3087), is amended to

read as follows:

“SECTION 1. Notwithstanding section 11(b)(1) of the Public Utility Holding Company Act of 1935,

a company registered under said Act, or a subsidiary company of such registered company, may acquire or

for any exemption relating to the Public Utility Holding Company Act of 1935 prescribed pursuant to section

210 of the Public Utility Regulatory Policies Act of 1978.

“SEC. 2. Nothing herein shall be construed to affect the applicability of section 3(17)(C) or section

3(18)(B) of the Federal Power Act or any provision of the Public Utility Holding Company Act of 1935, other

than section 11(b)(1), to the acquisition or retention of any such interest by any such company.”.

SEC. 714. BOOKS AND RECORDS.

Section 201 of the Federal Power Act is amended by adding the following new subsection at the end

thereof: 

may examine the books, accounts, memoranda, contracts, and records of—

“(A) an electric utility company subject to its regulatory authority under State law,

“(B) any exempt wholesale generator selling energy at wholesale to such electric utility, and

“(C) any electric utility company, or holding company thereof, which is an associate company or

affiliate of an exempt wholesale generator which sells electric energy to an electric utility company

referred to in subparagraph (A), wherever located, if such examination is required for the effective

discharge of the State commission's regulatory responsibilities affecting the provision of electric

service. 
166 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

“(2) Where a State commission issues an order pursuant to paragraph (1), the State commission shall

not publicly disclose trade secrets or sensitive commercial information.

“(3) Any United States district court located in the State in which the State commission referred to

in paragraph (1) is located shall have jurisdiction to enforce compliance with this subsection.

“(4) Nothing in this section shall—

“(A) preempt applicable State law concerning the provision of records and other information;

or

“(B) in any way limit rights to obtain records and other information under Federal law, contracts,

or otherwise. 

“(5) As used in this subsection the terms 'affiliate,' 'associate company', 'electric utility company',

'holding company', 'subsidiary company', and 'exempt wholesale generator' shall have the same meaning as

when used in the Public Utility Holding Company Act of 1935.”.

SEC. 715. INVESTMENT IN FOREIGN UTILITIES.

The Public Utility Holding Company Act of 1935 (15 U.S.C. 79 et seq.) is amended by inserting after

section 32 the following new section:

“SEC. 33. TREATMENT OF FOREIGN UTILITIES.

“(a) EXEMPTIONS FOR FOREIGN UTILITY COMPANIES.— 15 USC 79z-5b

“(1) IN GENERAL.—A foreign utility company shall be exempt from all of the provisions of this

Act, except as otherwise provided under this section, and shall not, for any purpose under this Act,

be deemed to be a public utility company under section 2(a)(5), notwithstanding that the foreign

utility company may be a subsidiary company, an affiliate, or an associate company of a holding

company or of a public utility company.

“(2) STATE COMMISSION CERTIFICATION.—Section (a)(1) shall not apply or be effective

unless every State commission having jurisdiction over the retail electric or gas rates of a public

utility company that is an associate company or an affiliate of a company otherwise exempted under

section (a)(1) (other than a public utility company that is an associate company or an affiliate of a

registered holding company) has certified to the Commission that it has the authority and resources

to protect ratepayers subject to its jurisdiction and that it intends to exercise its authority. Such

certification, upon the filing of a notice by such State commission, may be revised or withdrawn by

the State commission prospectively as to any future acquisition. The requirement of State

certification shall be deemed satisfied if the relevant State commission had, prior to the date of

enactment of this section, on the basis of prescribed conditions of general applicability, determined

that ratepayers of a public utility company are adequately insulated from the effects of

diversification and the diversification would not impair the ability of the State commission to

regulate effectively the operations of such company.

“(3) DEFINITION.—For purposes of this section, the term 'foreign utility company' means any

company that—

“(A) owns or operates facilities that are not located in any State and that are used for the

generation, transmission, or distribution of electric energy for sale or the distribution at retail of

natural or manufactured gas for heat, light, or power, if such company—

“(i) derives no part of its income, directly or indirectly, from the generation,

transmission, or distribution of electric energy for sale or the distribution at retail of natural

or manufactured gas for heat, light, or power, within the United States; and
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 167

Regulations interests in foreign utility companies which shall provide for the protection of the customers of a

“(ii) neither the company nor any of its subsidiary companies is a public utility company

operating in the United States; and

“(B) provides notice to the Commission, in such form as the Commission may prescribe, that such

company is a foreign utility company. 

“(b) OWNERSHIP OF FOREIGN UTILITY COMPANIES BY EXEMPT HOLDING

COMPANIES.—Notwithstanding any provision of this Act except as provided under this section, a holding

company that is exempt under section 3 of the Act shall be permitted without condition or limitation under

the Act to acquire and maintain an interest in the business of one or more foreign utility companies. 

“(c) REGISTERED HOLDING COMPANIES.—

“(1) OWNERSHIP OF FOREIGN UTILITY COMPANIES BY REGISTERED HOLDING

COMPANIES.—Notwithstanding any provision of this Act except as otherwise provided under this

section, a registered holding company shall be permitted as of the date of enactment of this section

(without the need to apply for or receive approval from the Commission) to acquire and hold the

securities or an interest in the business, of one or more foreign utility companies. The Commission

shall promulgate rules or regulations regarding registered holding companies' acquisition of

public utility company which is an associate company of a foreign utility company and the

maintenance of the financial integrity of the registered holding company system.

“(2) ISSUANCE OF SECURITIES.—The issuance of securities by a registered holding company

for purposes of financing the acquisition of a foreign utility company, the guarantee of securities of

a foreign utility company by a registered holding company, the entering into service, sales, or

construction contracts, and the creation or maintenance of any other relationship between a foreign

utility company and a registered holding company, its affiliates and associate companies, shall

remain subject to the jurisdiction of the Commission under this Act (unless otherwise exempted

under this Act, in the case of a transaction with an affiliate or associate company located outside of

the United States). Any State commission with jurisdiction over the retail rates of a public utility

company which is part of a registered holding company system may make such recommendations

to the Commission regarding the registered holding company's relationship to a foreign utility company, and the Commission shall reasonably and fully consider such State recommendation.

“(3) CONSTRUCTION.—Any interest in the business of 1 or more foreign utility companies, or

1 or more companies organized exclusively to own, directly or indirectly, the securities or other

interest in a foreign utility company, shall for all purposes of this Act, be considered to be—

“(A) consistent with the operation of a single integrated public utility system, within the

meaning of section 11; and

“(B) reasonably incidental, or economically necessary or appropriate, to the operations of an

integrated public utility system, within the meaning of section 11.

“(d) EFFECT ON EXISTING LAW; NO STATE PREEMPTION.—Nothing in this section shall—

“(1) preclude any person from qualifying for or maintaining any exemption otherwise provided

for under this Act or the rules, regulations, or orders promulgated or issued under this Act; or

“(2) be deemed or construed to limit the authority of any State (including any State regulatory

authority) with respect to—

“(A) any public utility company or holding company subject to such State's jurisdiction; or

“(B) any transaction between any foreign utility company (or any affiliate or associate

company thereof) and any public utility company or holding company subject to such State's

jurisdiction. 
168 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

“(e) REPORTING REQUIREMENTS.—

“(1) FILING OF REPORTS.—A public utility company that is an associate company of a foreign

utility company shall file with the Commission such reports (with respect to such foreign utility

company) as the Commission may by rules, regulations, or order prescribe as necessary or

appropriate in the public interest or for the protection of investors or consumers.

“(2) NOTICE OF ACQUISITIONS.—Not later than 30 days after the consummation of the

acquisition of an interest in a foreign utility company by an associate company of a public utility

company that is subject to the jurisdiction of a State commission with respect to its retail electric or

gas rates or by such public utility company, such associate company or such public utility company,

shall provide notice of such acquisition to every State commission having jurisdiction over the retail

electric or gas rates of such public utility company, in such form as may be prescribed by the State

commission.

“(f) PROHIBITION ON ASSUMPTION OF LIABILITIES.—

“(1) IN GENERAL.—No public utility company that is subject to the jurisdiction of a State

commission with respect to its retail electric or gas rates shall issue any security for the purpose of

financing the acquisition, or for the purposes of financing the ownership or operation, of a foreign

utility company, nor shall any such public utility company assume any obligation or liability as

guarantor, endorser, surety, or otherwise in respect of any security of a foreign utility company.

“(2) EXCEPTION FOR HOLDING COMPANIES WHICH ARE PREDOMINANTLY PUBLIC

UTILITY COMPANIES.—Subsection (f)(1) shall not apply if:

“(A) the public utility company that is subject to the jurisdiction of a State commission with

respect to its retail electric or gas rates is a holding company and is not an affiliate under section

2(a)(11)(B) of another holding company or is not subject to regulation as a holding company and

has no affiliate as defined in section 2(a)(11)(A) that is a public utility company subject to the

jurisdiction of a State commission with respect to its retail electric or gas rates; and 

“(B) each State commission having jurisdiction with respect to the retail electric and gas rates

of such public utility company expressly permits such public utility to engage in a transaction

otherwise prohibited under section (f)(1); and

“(C) the transaction (aggregated with all other then outstanding transactions exempted

under this subsection) does not exceed 5 per centum of the then- outstanding total capitalization

of the public utility.

“(g) PROHIBITION ON PLEDGING OR ENCUMBERING UTILITY ASSETS.—No public utility

company that is subject to the jurisdiction of a State commission with respect to its retail electric or

gas rates shall pledge or encumber any utility assets or utility assets of any subsidiary thereof for

the benefit of an associate foreign utility company.”.

Subtitle B — Federal Power Act; 

Interstate Commerce in Electricity

SEC. 721. AMENDMENTS TO SECTION 211 OF FEDERAL POWER ACT.

Section 211 of the Federal Power Act (16 U.S.C. 824j) is amended as follows:

(1) The first sentence of subsection (a) is amended to read as follows: “Any electric utility, Federal

power marketing agency, or any other person generating electric energy for sale for resale, may

apply to the Commission for an order under this subsection requiring a transmitting utility to

provide transmission services (including any enlargement of transmission capacity necessary to

provide such services) to the applicant.”.

 (2) In the second sentence of subsection (a), strike “the Commission may” and all that follows

and insert “the Commission may issue such order if it finds that such order meets
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 169

16 USC 824k. “(a) RATES, CHARGES, TERMS, AND CONDITIONS FOR WHOLESALE TRANSMISSION

the requirements of section 212, and would otherwise be in the public interest. No order may be issued under

this subsection unless the applicant has made a request for transmission services to the transmitting utility

that would be the subject of such order at least 60 days prior to its filing of an application for such order.”.

(3) Amend subsection (b) to read as follows:

“(b) RELIABILITY OF ELECTRIC SERVICE.—No order may be issued under this section or section

210 if, after giving consideration to consistently applied regional or national reliability standards, guidelines,

or criteria, the Commission finds that such order would unreasonably impair the continued reliability of

electric systems affected by the order.”.

(4) In subsection (c)—

(A) Strike out paragraph (1).

(B) In paragraph (2) strike “which requires the electric” and insert “which requires the

transmitting”.

(C) Strike out paragraphs (3) and (4). 

(5) In subsection (d)—

(A) In the first sentence of paragraph (1), strike “electric” and insert “transmitting” in each

place it appears.

(B) In the second sentence of paragraph (1) before “and each affected electric utility,” insert

“each affected transmitting utility,”.

(C) In paragraph (3), strike “electric” and insert “transmitting”.

(D) Strike the period in subparagraph (B) of paragraph (1) and insert “, or” and after

subparagraph (B) insert the following new subparagraph:

“(C) the ordered transmission services require enlargement of transmission capacity and the

transmitting utility subject to the order has failed, after making a good faith effort, to obtain the

necessary approvals or property rights under applicable Federal, State, and local laws.”.

SEC. 722. TRANSMISSION SERVICES.

Section 212 of the Federal Power Act is amended as follows:

(1) Strike subsections (a) and (b) and insert the following:

SERVICES.—An order under section 211 shall require the transmitting utility subject to the order to provide

wholesale transmission services at rates, charges, terms, and conditions which permit the recovery by such

utility of all the costs incurred in connection with the transmission services and necessary associated services,

including, but not limited to, an appropriate share, if any, of legitimate, verifiable and economic costs,

including taking into account any benefits to the transmission system of providing the transmission service,

and the costs of any enlargement of transmission facilities. Such rates, charges, terms, and conditions shall

promote the economically efficient transmission and generation of electricity and shall be just and reasonable,

and not unduly discriminatory or preferential. Rates, charges, terms, and conditions for transmission services

provided pursuant to an order under section 211 shall ensure that to the extent practicable, costs incurred in

providing the wholesale transmission services, and properly allocable to the provision of such services, are

recovered from the applicant for such order and not from a transmitting utility's existing wholesale, retail, and

transmission customers.”. 

(2) Subsection (e) is amended to read as follows:

“(e) SAVINGS PROVISIONS.—(1) No provision of section 210, 211, 214, or this section shall be treated

as requiring any person to utilize the authority of any such section in lieu of any other authority of law. Except

as provided in section 210, 211, 214, or this section, such sections shall not be construed as limiting or

impairing any authority of the Commission under any other provision of law.

“(2) Sections 210, 211, 213, 214, and this section, shall not be construed to modify, impair, or

supersede the antitrust laws. For purposes of this section, the term ‘antitrust laws’ has the 
170 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

meaning given in subsection (a) of the first sentence of the Clayton Act, except that such term includes section

5 of the Federal Trade Commission Act to the extent that such section relates to unfair methods of

competition.”.

(3) Add the following new subsections at the end thereof: 

“(g) PROHIBITION ON ORDERS INCONSISTENT WITH RETAIL MARKETING AREAS.—No order

may be issued under this Act which is inconsistent with any State law which governs the retail marketing

areas of electric utilities.

“(h) PROHIBITION ON MANDATORY RETAIL WHEELING AND SHAM WHOLESALE

TRANSACTIONS.—No order issued under this Act shall be conditioned upon or require the transmission

of electric energy:

“(1) directly to an ultimate consumer, or

“(2) to, or for the benefit of, an entity if such electric energy would be sold by such entity directly to

an ultimate consumer, unless:

“(A) such entity is a Federal power marketing agency; the Tennessee Valley Authority; a State

or any political subdivision of a State (or an agency, authority, or instrumentality of a State or a

political subdivision); a corporation or association that has ever received a loan for the purposes of

providing electric service from the Administrator of the Rural Electrification Administration under

the Rural Electrification Act of 1936; a person having an obligation arising under State or local law

(exclusive of an obligation arising solely from a contract entered into by such person) to provide

electric service to the public; or any corporation or association which is wholly owned directly or

indirectly, by any one or more of the foregoing; and

“(B) such entity was providing electric service to such ultimate consumer on the date of

enactment of this subsection or would utilize transmission or distribution facilities that it owns or

controls to deliver all such electric energy to such electric consumer.

Nothing in this subsection shall affect any authority of any State or local government under State law

concerning the transmission of electric energy directly to an ultimate consumer.”.

“(i) LAWS APPLICABLE TO FEDERAL COLUMBIA RIVER TRANSMISSION SYSTEM.—(1) The

Commission shall have authority pursuant to section 210, section 211, this section, and section 213 to (A) order

the Administrator of the Bonneville Power Administration to provide transmission service and (B) establish

the terms and conditions of such service. In applying such sections to the Federal Columbia River

Transmission System, the Commission shall assure that—

“(i) the provisions of otherwise applicable Federal laws shall continue in full force and effect and

shall continue to be applicable to the system; and 

“(ii) the rates for the transmission of electric power on the system shall be governed only by such

otherwise applicable provisions of law and not by any provision of section 210, section 211, this

section, or section 213, except that no rate for the transmission of power on the system shall be unjust

unreasonable, or unduly discriminatory or preferential, as determined by the Commission.

“(2) Notwithstanding any other provision of this Act with respect to the procedures for the

determination of terms and conditions for transmission service—

“(A) when the Administrator of the Bonneville Power Administration either (i) in response to

a written request for specific transmission service terms and conditions does not offer the requested

terms and conditions, or (ii) proposes to establish terms and conditions of general applicability for

transmission service on the Federal Columbia River Transmission System, then the Administrator

may provide opportunity for a hearing and, in so doing, shall—

“(I) give notice in the Federal Register and state in such notice the written explanation of the

reasons why the specific terms and conditions for transmission services are not being offered or

are being proposed;

“(II) adhere to the procedural requirements of Paragraphs (1) through (3) of section 7(i) of

the Pacific Northwest Electric Power Planning and Conservation Act (16 U.S.C. 839(i) (1) through

(3)), except that the hearing officer shall, unless the hearing officer becomes unavailable to the

agency, make a recommended decision to the Administrator 
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 171

that states the hearing officer's findings and conclusions, and the reasons or basis thereof, on

all material issues of fact, law, or discretion presented on the record; and

“(III) make a determination, setting forth the reasons for reaching any findings and

conclusions which may differ from those of the hearing officer, based on the hearing record,

consideration of the hearing officer's recommended decision, section 211 and this section, as

amended by the Energy Policy Act of 1992, and the provisions of law as preserved in this section;

and

“(B) if application is made to the Commission under section 211 for transmission service under

terms and conditions different than those offered by the Administrator, or following the denial of

a request for transmission service by the Administrator, and such application is filed within 60 days

of the Administrator's final determination and in accordance with Commission procedures, the

Commission shall—

“(i) in the event the Administrator has conducted a hearing as herein provided for (I) accord

parties to the Administrator's hearing the opportunity to offer for the Commission record

materials excluded by the Administrator from the hearing record, (II) accord such parties the

opportunity to submit for the Commission record comments on appropriate terms and

conditions, (III) afford those parties the opportunity for a hearing if and to the extent that the

Commission finds the Administrator's hearing record to be inadequate to support a decision by

the Commission, and (IV) establish terms and conditions for or deny transmission service based

on the Administrator's hearing record, the Commission record, section 211 and this section, as

amended by the Energy Policy Act of 1992, and the provisions of law as preserved in this section,

or

“(ii) in the event the Administrator has not conducted a hearing as herein provided for,

determine whether to issue an order for transmission service in accordance with section 211 and

this section, including providing the opportunity for a hearing.

“(3) Notwithstanding those provisions of section 313(b) of this Act (16 U.S.C. 825l) which designate

the court in which review may be obtained, any party to a proceeding concerning transmission service sought

to be furnished by the Administrator of the Bonneville Power Administration seeking review of an order

issued by the Commission in such proceeding shall obtain a review of such order in the United States Court

of Appeals for the Pacific Northwest, as that region is defined by section 3(14) of the Pacific Northwest Electric

Power Planning and Conservation Act (16 U.S.C. 839a( 14)).

“(4) To the extent the Administrator of the Bonneville Power Administration cannot be required

under section 211, as a result of the Administrator's other statutory mandates, either to (A) provide

transmission service to an applicant which the Commission would otherwise order, or (B) provide such service

under rates, terms, and conditions which the Commission would otherwise require, the applicant shall not

be required to provide similar transmission services to the Administrator or to provide such services under

similar rates, terms and conditions.

“(5) The Commission shall not issue any order under section 210, section 211, this section, or section

213 requiring the Administrator of the Bonneville Power Administration to provide transmission service if

such an order would impair the Administrator's ability to provide such transmission service to the

Administrator's power and transmission customers in the Pacific Northwest, as that region is defined in

section 3(14) of the Pacific Northwest Electric Power Planning and Conservation Act (16 U.S.C. 839a(14)), as

is needed to assure adequate and reliable service to loads in that region.

“(j) EQUITABILITY WITHIN TERRITORY RESTRICTED ELECTRIC SYSTEMS.—With respect to an

electric utility which is prohibited by Federal law from being a source of power supply, either directly or

through a distributor of its electric energy, outside an area set forth in such law, no order issued under section

211 may require such electric utility (or a distributor of such electric utility) to provide transmission services

to another entity if the electric energy to be transmitted will be consumed within the area set forth in such

Federal law, unless the order is in furtherance of a sale of electric energy to that electric utility: Provided,

however, That the foregoing provision shall not apply to any area served at retail by an electric transmission

system which was such a distributor on the date of enactment of this subsection and which before October

1, 1991, gave its notice of termination under its power supply contract with such electric utility.
172 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

“(k) ERCOT UTILITIES.—

“(1) RATES.—Any order under section 211 requiring provision of transmission services in whole

or in part within ERCOT shall provide that any ERCOT utility which is not a public utility and the

transmission facilities of which are actually used for such transmission service is entitled to receive

compensation based, insofar as practicable and consistent with subsection (a), on the transmission

ratemaking methodology used by the Public Utility Commission of Texas.

“(2) DEFINITIONS.—For purposes of this subsection—

“(A) the term 'ERCOT' means the Electric Reliability Council of Texas; and

“(B) the term 'ERCOT utility' means a transmitting utility which is a member of ERCOT.”.

“SEC. 723. INFORMATION REQUIREMENTS. 

Part II of the Federal Power Act is amended by adding the following new section after section 212:

“SEC. 213. INFORMATION REQUIREMENTS.

“(a) REQUESTS FOR WHOLESALE TRANSMISSION SERVICES.— Whenever any electric utility,

Federal power marketing agency, or any other person generating electric energy for sale for resale makes a

good faith request to a transmitting utility to provide wholesale transmission services and requests specific 16 USC 824l.

rates and charges, and other terms and conditions, unless the transmitting utility agrees to provide such

services at rates, charges, terms and conditions acceptable to such person, the transmitting utility shall, within

60 days of its receipt of the request, or other mutually agreed upon period, provide such person with a

detailed written explanation, with specific reference to the facts and circumstances of the request, stating (1)

the transmitting utility's basis for the proposed rates, charges, terms and conditions for such services and (2)

its analysis of any physical or other constraints affecting the provision of such services. 

“(b) TRANSMISSION CAPACITY AND CONSTRUCTS.—Not later than 1 year after the enactment

of this section, the Commission shall promulgate a rule requiring that information be submitted annually to

the Commission by transmitting utilities which is adequate to inform potential transmission customers, State

regulatory authorities, and the public of potentially available transmission capacity and known constraints.”.

SEC. 724. SALES BY EXEMPT WHOLESALE GENERATORS.

Part II of the Federal Power Act is amended by adding the following new section after section 213: Regulations.

“SEC. 214. SALES BY EXEMPT WHOLESALE GENERATORS.

“No rate or charge received by an exempt wholesale generator for the sale of electric energy shall

be lawful under section 205 if, after notice and opportunity for hearing, the Commission finds that such rate

or charge results from the receipt of any undue preference or advantage from an electric utility which is an

associate company or an affiliate of the exempt wholesale generator. For purposes of this section, the terms

'associate company' and 'affiliate' shall have the same meaning as provided in section 2(a) of the Public Utility

Holding Company Act of 1935.”.

SEC. 725. PENALTIES.

(a) EXISTING PENALTIES NOT APPLICABLE TO TRANSMISSION PROVISIONS.—Sections 315

and 316 of the Federal Power Act are each amended by adding the

16 USC 824m.

16 USC 825n,

825o
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 173

16 USC 825o-1.

16 USC 796. following at the end thereof:

15 USC 79 note.

 following at the end thereof:

“(c) This subsection shall not apply in the case of any provision of section 211, 212, 213, or 214 or any

rule or order issued under any such provision.”.

(b) PENALTIES APPLICABLE TO TRANSMISSION PROVISIONS.—Title III of the Federal Power

Act is amended by inserting the following new section after section 316:

“SEC. 316A. ENFORCEMENT OF CERTAIN PROVISIONS.

“(a) VIOLATIONS.—It shall be unlawful for any person to violate any provision of section 211, 212,

213, or 214 or any rule or order issued under any such provision.

“(b) CIVIL PENALTIES.—Any person who violates any provision of section 211, 212, 213, or 214 or

any provision of any rule or order thereunder shall be subject to a civil penalty of not more than $10,000 for

each day that such violation continues. Such penalty shall be assessed by the Commission, after notice and

opportunity for public hearing, in accordance with the same provisions as are applicable under section 31(d)

in the case of civil penalties assessed under section 31. In determining the amount of a proposed penalty, the

Commission shall take into consideration the seriousness of the violation and the efforts of such person to

remedy the violation in a timely manner.”.

SEC. 726. DEFINITIONS.

(a) ADDITIONAL DEFINITIONS.—Section 3 of the Federal Power Act is amended by adding the

“(23) TRANSMITTING UTILITY.—The term 'transmitting utility' means any electric utility,

qualifying cogeneration facility, qualifying small power production facility, or Federal power

marketing agency which owns or operates electric power transmission facilities which are used for

the sale of electric energy at wholesale.

“(24) WHOLESALE TRANSMISSION SERVICES.—The term 'wholesale transmission services'

means the transmission of electric energy sold, or to be sold, at wholesale in interstate commerce.

“(25) EXEMPT WHOLESALE GENERATOR.—The term 'exempt wholesale generator' shall have

the meaning provided by section 32 of the Public Utility Holding Company Act of 1935.”.

(b) CLARIFICATION OF TERMS.—Section 3(22) of the Federal Power Act is amended by inserting

“(including any municipality)” after “State agency”.

Subtitle C—State and Local Authorities

SEC. 731. STATE AUTHORITIES. 

Nothing in this title or in any amendment made by this title shall be construed as affecting or intending to

affect, or in any way to interfere with, the authority of any State or local government relating to environmental

protection or the siting of facilities.
Appendix G

Selected Provisions of

the Federal Power Act

Referenced in the FERC

Mega-NOPR
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 177

Appendix G

Selected Provisions of the Federal Power Act

Referenced in the FERC Mega-NOPR

RATE AND CHARGES; SCHEDULES; SUSPENSION OF NEW RATES

SEC. 205. (a) All rates and charges made, demanded, or received by any public utility for or in connection with the transmission or sale of electric energy subject to the jurisdiction of the Commission, and all rules and regulations affecting or pertaining

to such rates or charges shall be just and reasonable, and any such rate or charge that is not just and reasonable is hereby declared to

be unlawful.

(b) No public utility shall, with respect to any transmission or sale subject to the jurisdiction of the Commission, (1) make or

grant any undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage, or (2) maintain

any unreasonable difference in rates, charges, service, facilities, or in any other respect, either as between localities or as between

classes of service.

(c)Under such rules and regulations as the Commission may prescribe, every public utility shall file with the Commission,

within such time and in such form as the Commission may designate, and shall keep open in convenient form and place for public

inspection schedules showing all rates and charges for any transmission or sale subject to the jurisdiction of the Commission, and the

classification, practices, and regulations affecting such rates and charges, together with all contracts which in any manner affect or

relate to such rates, charges, classifications, and services.

(d) Unless the Commission otherwise orders, no change shall be made by any public utility in any such rates, charges,

classification, or service, or in any rule, regulation, or contract relating thereto, except after sixty days' notice to the Commission and

to the public. Such notice shall be given by filing with the Commission and keeping open for public inspection new schedules stating

plainly the change or changes to be made in the schedule or schedules then in force and the time when the change or changes will go

into effect. The Commission, for good cause shown, may allow changes to take effect without requiring the sixty days' notice herein

provided for by an order specifying the changes so to be made and the time when they shall take effect and the manner in which they

shall be filed and published.

(e) Whenever any such new schedule is filed the Commission shall have authority, either upon complaint or upon its own

initiative without complaint at once, and, if it so orders, without answer or formal pleading by the public utility, but upon reasonable

notice to enter upon a hearing concerning the lawfulness of such rate, charge, classification, or service; and, pending such hearing and

the decision thereon the Commission, upon filing with such schedules and delivering to the public utility affected thereby a statement

in writing of its reasons for such suspension, may suspend the operation of such schedule and defer the use of such rate, charge, classification, or service, but not for a longer period than five months beyond the time when it would otherwise go into effect; and after

full hearings, either completed before or after the rate, charge, classification, or service goes into effect, the Commission may make

such orders with reference thereto as would be proper in a proceeding initiated after it had become effective. If the proceeding has

not been concluded and an order made at the expiration of such five months, the proposed change of rate, charge, classification, or

service shall go into effect at the end of such period, but in case of a proposed increased rate or charge, the Commission may by order

require the interested public utility or public utilities to keep accurate account in detail of all amounts received by reason of such increase, specifying by whom and in whose behalf such amounts are paid, and upon completion of the hearing and decision may by

further order require such public utility or public utilities to refund with interest, to the persons in whose behalf such amounts were

paid, such portion of such increased rates or charges as by its decision shall be found not justified. At any hearing involving a rate or

charge sought to be increased, the burden of proof to show that the increased rate or charge is just and reasonable shall be upon the

public utility, and the Commission shall give to the hearing and decision of such questions preference over other questions pending

before it and decide the same as speedily as possible.

(f)(1) Not later than 2 years after the date of the enactment of this subsection and not less often than every 4 years thereafter,

the Commission shall make a thorough review of automatic adjustment clauses in public utility rate schedules to examine—

(A) whether or not each such clause effectively provides incentives for efficient use of resources (including economical

purchase and use of fuel and electric energy), and 

(B) whether any such clause reflects any costs other than costs which are—

(i) subject to periodic fluctuations, and 

(ii) not susceptible to precise determinations in rate cases prior to the time such costs are incurred.

Such review may take place in individual rate proceedings or in generic or other separate proceedings applicable to one or more utilities.
178 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

(2) Not less frequently than every 2 years, in rate proceedings or in generic or other separate proceedings, the Commission

shall review, with respect to each public utility, practices under any automatic adjustment clauses of such utility to insure efficient use

of resources (including economical purchase and use of fuel and electric energy) under such clauses.

(3) The Commission may, on its own motion or upon complaint, after an opportunity for an evidentiary hearing, order a

public utility to—

(A) modify the terms and provisions of any automatic adjustment clause, or

(B) cease any practice in connection with the clause, if such clause or practice does not result in the economical purchase

and use of fuel, electric energy, or other items, the cost of which is included in any rate schedule under an automatic adjustment clause.

(4) As used in this subsection, the term “automatic adjustment clause” means a provision of a rate schedule which provides

for increases or decreases (or both), without prior hearing, in rates reflecting increases or decreases (or both) in costs incurred by an

electric utility. Such term does not include any rate which takes effect subject to refund and subject to a later determination of the

appropriate amount of such rate.

(16 U.S.C. 824d)

FIXING RATES AND CHARGES; DETERMINATION OF COST OF PRODUCTION OR TRANSPORTATION

SEC. 206. (a) Whenever the Commission, after a hearing had upon its own motion or upon complaint, shall find that any rate,

charges, or classification demanded, observed, charged, or collected by any public utility for any transmission or sale subject to the

jurisdiction of the Commission, or that any rule, regulation, practice, or contract affecting such rate, charge, or classification is unjust,

unreasonable, unduly discriminatory or preferential, the Commission shall determine the just and reasonable rate, charge, classification, rule, regulation, practice, or contract to be thereafter observed and in force, and shall fix the same by order.

(b) Whenever the Commission institutes a proceeding under this section, the Commission shall establish a refund effective

date. In the case of a proceeding instituted on complaint, the refund effective date shall not be earlier than the date 60 days after the

filing of such complaint nor later than 5 months after the expiration of such 60-day period. In the case of a proceeding instituted by

the Commission on its own motion, the refund effective date shall not be earlier than the date 60 days after the publication by the Commission of notice of its intention to initiate such proceeding nor later than 5 months after the expiration of such 60-day period. Upon

institution of a proceeding under this section, the Commission shall give to the decision of such proceeding the same preference as

provided under section 205 of this Act and otherwise act as speedily as possible. If no final decision is rendered by the refund effective

date or by the conclusion of the 180-day period commencing upon initiation of a proceeding pursuant to this section, whichever is

earlier, the Commission shall state the reasons why it has failed to do so and shall state its best estimate as to when it reasonably

expects to make such decision. In any proceeding under this section, the burden of proof to show that any rate, charge, classification,

rule, regulation, practice, or contract is unjust, unreasonable, unduly discriminatory, or preferential shall be upon the Commission

or the complainant. At the conclusion of any proceeding under this section, the Commission may order the public utility to make

refunds of any amounts paid, for the period subsequent to the refund effective date through a date fifteen months after such refund

effective date, in excess of those which would have been paid under the just and reasonable rate, charge, classification, rule, regulation,

practice, or contract which the Commission orders to be thereafter observed and in force: Provided, That if the proceeding is not

concluded within fifteen months after the refund effective date and if the Commission determines at the conclusion of the proceeding

that the proceeding was not resolved within the fifteen-month period primarily because of dilatory behavior by the public utility, the

Commission may order refunds of any or all amounts paid for the period subsequent to the refund effective date and prior to the

conclusion of the proceeding. The refunds shall be made, with interest, to those persons who have paid those rates or charges which

are the subject of the proceeding.

(c) Notwithstanding subsection (b), in a proceeding commenced under this section involving two or more electric utility

companies of a registered holding company, refunds which might otherwise be payable under subsection (b) shall not be ordered to

the extent that such refunds would result from any portion of a Commission order that (1) requires a decrease in system production

or transmission costs to be paid by one or more of such electric companies; and (2) is based upon a determination that the amount of

such decrease should be paid through an increase in the costs to be paid by other electric utility companies of such registered holding

company: Provided, That refunds, in whole or in part, may be ordered by the Commission if it determines that the registered holding

company would not experience any reduction in revenues which results from an inability of an electric utility company of the holding

company to recover such increase in costs for the period between the refund effective date and the effective date of the Commission's

order. For purposes of this subsection, the terms “electric utility companies” and “registered holding company” shall have the same

meanings as provided in the Public Utility Holding Company Act of 1935, as amended.

(d) The Commission upon its own motion, or upon the request of any State commission whenever it can do so without

prejudice to the efficient and proper conduct of its affairs, may investigate and determine the cost of the production or transmission

of electric energy by means of facilities under the jurisdiction of the Commission in cases where the Commission has no authority to

establish a rate governing the sale of such energy.

(16 U.S.C. 824i)
 Section 721(4) of P.L. 102-486 struck paragraphs (1), (3), and (4) without redesgnating paragraph (2). 285

Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 179

CERTAIN WHEELING AUTHORITY

SEC. 211. (a) Any electric utility, Federal power marketing agency, or any other person generating electric energy for sale

for resale, may apply to the Commission for an order under this subsection requiring a transmitting utility to provide transmission

services (including any enlargement of transmission capacity necessary to provide such services) to the applicant. Upon receipt of such

application, after public notice and notice to each affected State regulatory authority, each affected electric utility, and each affected

Federal power marketing agency, and after affording an opportunity for an evidentiary hearing, the Commission may issue such order

if it finds that such order meets the requirements of section 212, and would otherwise be in the public interest. No order may be issued

under this subsection unless the applicant has made a request for transmission services to the transmitting utility that would be the

subject of such order at least 60 days prior to its filing of an application for such order.

(b) RELIABILITY OF ELECTRIC SERVICE.—No order may be issued under this section or section 210 if, after giving

consideration to consistently applied regional or national reliability standards, guidelines, or criteria, the Commission finds that such

order would unreasonably impair the continued reliability of electric systems affected by the order.

(c)(2) No order may be issued under subsection (a) or (b) which requires the transmitting utility subject to the order to 285

transmit, during any period, an amount of electric energy which replaces any amount of electric energy—

(A) required to be provided to such applicant pursuant to a contract during such period, or 

(B) currently provided to the applicant by the utility subject to the order pursuant to a rate schedule on file during such

period with the Commission: Provided, That nothing in this subparagraph shall prevent an application for an order hereunder

to be filed prior to termination of modification of an existing rate schedule: Provided, That such order shall not become

effective until termination of such rate schedule or the modification becomes effective.

(d)(1) Any transmitting utility ordered under subsection (a) or (b) to provide transmission services may apply to the

Commission for an order permitting such transmitting utility to cease providing all, or any portion of, such services. After public

notice, notice to each affected State regulatory authority, each affected Federal power marketing agency, each affected transmitting

utility, and each affected electric utility, and after an opportunity for an evidentiary hearing, the Commission shall issue an order

terminating or modifying the order issued under subsection (a) or (b), if the electric utility providing such transmission services has

demonstrated, and the Commission has found, that—

(A) due to changed circumstances, the requirements applicable, under this section and section 212, to the issuance of

an order under subsection (a) or (b) are no longer met, or

(B) any transmission capacity of the utility providing transmission services under such order which was, at the time

such order was issued, in excess of the capacity necessary to serve its own customers is no longer in excess of the capacity

necessary for such purposes, or

(C) the ordered transmission services require enlargement of transmission capacity and the transmitting utility subject

to the order has failed, after making a good faith effort, to obtain the necessary approvals or property rights under applicable

Federal, State, and local laws.

No order shall be issued under this subsection pursuant to a finding under subparagraph (A) unless the Commission finds that such

order is in the public interest.

(2) Any order issued under this subsection terminating or modifying an order issued under subsection (a) or (b) shall—

(A) provide for any appropriate compensation, and

(B) provide the affected electric utilities adequate opportunity and time to—

(i) make suitable alternative arrangements for any transmission services terminated or modified, and

(ii) insure that the interests of ratepayers of such utilities are adequately protected.

(3) No order may be issued under this subsection terminating or modifying any order issued under subsection (a) or (b) if

the order under subsection (a) or (b) includes terms and conditions agreed among by the parties which—

(A) fix a period during which transmission services are to be provided under the order under subsection (a) or (b), or

(B) otherwise provide procedures or methods for terminating or modifying such order (including, if appropriate, the

return of the transmission capacity when necessary to take into account an increase, after the issuance of such order, in the

needs of the transmitting utility subject to such order for transmission capacity).

(e) As used in this section, the term “ facilities” means only facilities used for the generation or transmission of electric energy.

(16 U.S.C. 824j)

PROVISIONS REGARDING CERTAIN ORDERS REQUIRING INTERCONNECTION OR WHEELING

SEC. 212. (a) RATES, CHARGES, TERMS, AND CONDITIONS FOR WHOLESALE TRANSMISSION SERVICES.—An order

under section 211 shall require the transmitting utility subject to the order to provide wholesale transmission services at rates, charges,

terms, and conditions which permit the recovery by such utility of all the costs incurred in connection with the transmission services

and necessary associated services, including, but not limited to, an appropriate share, if any, of legitimate, verifiable and economic

costs, including taking into account any benefits to the transmission system of providing the transmission service, and the costs of any
180 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

enlargement of transmission facilities. Such rates, charges, terms, and conditions shall promote the economically efficient transmission

and generation of electricity and shall be just and reasonable, and not unduly discriminatory or preferential. Rates, charges, terms,

and conditions for transmission services provided pursuant to an order under section 211 shall ensure that, to the extent practicable,

costs incurred in providing the wholesale transmission services, and properly allocable to the provision of such services, are recovered

from the applicant for such order and not from a transmitting utility's existing wholesale, retail, and transmission customers.

[Subsection (b) repealed]

(c)(1) Before issuing an order under section 210 of subsection (a) or (b) of section 211, the Commission shall issue a proposed

order and set a reasonable time for parties to the proposed interconnection or transmission order to agree to terms and conditions

under which such order is to be carried out, including the apportionment of costs between them and the compensation or

reimbursement reasonably due to any of them. Such proposed order shall not be reviewable or enforceable in any court. The time set

for such parties to agree to such terms and conditions may be shortened if the Commission determines that delay would jeopardize

the attainment of the purposes of any proposed order. Any terms and conditions agreed to by the parties shall be subject to the

approval of the Commission.

(2)(A) If the parties agree as provided in paragraph (1) within the time set by the Commission and the Commission approves

such agreement, the terms and conditions shall be included in the final order. In the case of an order under section 210, if the parties

fail to agree within the time set by the Commission or if the Commission does not approve any such agreement, the Commission shall

prescribe such terms and conditions and include such terms and conditions in the final order.

(B) In the case of any order applied for under section 211, if the parties fail to agree within the time set by the Commission,

the Commission shall prescribe such terms and conditions in the final order.

(d) If the Commission does not issue any order applied for under section 210 or 211, the Commission shall, by order, deny

such application and state the reasons for such denial.

(e) SAVINGS PROVISIONS.—(1) No provision of section 210, 211, 214, or this section shall be treated as requiring any person

to utilize the authority of any such section in lieu of any other authority of law. Except as provided in section 210, 211, 214, or this

section, such sections shall not be construed as limiting or impairing any authority of the Commission under any other provision of

law.

(2) Sections 210, 211, 213, 214, and this section, shall not be construed to modify, impair, or supersede the antitrust laws. For

purposes of this section, the term “antitrust laws” has the meaning given in subsection (a) of the first sentence of the Clayton Act,

except that such term includes section 5 of the Federal Trade Commission Act to the extent that such section relates to unfair methods

of competition.

(f)(1) No order under section 210 or 211 requiring the Tennessee Valley Authority (hereinafter in this subsection referred to

as the “TVA”) to take any action shall take effect for 60 days following the date of issuance of the order. Within 60 days following the

issuance by the Commission of any order under section 210 or of section 211 requiring the TVA to enter into any contract for the sale

or delivery of power, the Commission may on its own motion initiate, or upon petition of any aggrieved person shall initiate, an

evidentiary hearing to determine whether or not such sale or delivery would result in violation of the third sentence of section 15d(a)

of the Tennessee Valley Authority Act of 1933 (16 U.S.C. 831n —4), hereinafter in this subsection referred to as the TVA Act.

(2) Upon initiation of any evidentiary hearing under paragraph (1), the Commission shall give notice thereof to any applicant

who applied for and obtained the order from the Commission, to any electric utility or other entity subject to such order, and to the

public, and shall promptly make the determination referred to in paragraph (1). Upon initiation of such hearing, the Commission shall

stay the effectiveness of the order under section 210 or 211 until whichever of the following dates is applicable—

(A) the date on which there is a final determination (including any judicial review thereof under paragraph (3)) that

no such violation would result from such order, or

(B) the date on which a specific authorization of the Congress (within the meaning of the third sentence of section 15d(a)

of the TVA Act) takes effect.

(3) Any determination under paragraph (1) shall be reviewable only in the appropriate court of the United States upon

petition filed by any aggrieved person or municipality within 60 days after such determination, and such court shall have jurisdiction

to grant appropriate relief. Any applicant who applied for and obtained the order under section 210 or 211, and any electric utility or

other entity subject to such order shall have the right to intervene in and such proceeding in such court. Except for review by such court

(and any appeal or other review by an appellate court of the United States), no court shall have jurisdiction to consider any action

brought by any person to enjoin the carrying out of any order of the Commission under section 210 or section 211 requiring the TVA

to take any action on the grounds that such action requires a specific authorization of the Congress pursuant to the third sentence of

section 15d(a) of the TVA Act.

(g) PROHIBITION ON ORDERS INCONSISTENT WITH RETAIL MARKETING AREAS.—No order may be issued under

this Act which is inconsistent with any State law which governs the retail marketing areas of electric utilities.

(h) PROHIBITION ON MANDATORY RETAIL WHEELING AND SHAM WHOLESALE TRANSACTIONS.—No order

issued under this Act shall be conditioned upon or require the transmission of electric energy: 

(1) directly to an ultimate consumer, or

(2) to, or for the benefit of, an entity if such electric energy would be sold by such entity directly to an ultimate

consumer, unless:

(A) such entity is a Federal power marketing agency; the Tennessee Valley Authority; a State or any political

subdivision of a State (or an agency, authority, or instrumentality of a State or a political subdivision); a corporation

or association that has ever received a loan for the purposes of providing electric service from the Administrator of the

Rural Electrification Administration under the Rural Electrification Act of 1936; a person having an obligation arising
Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update 181

under State or local law (exclusive of an obligation arising solely from a contract entered into by such person) to

provide electric service to the public; or any corporation or association which is wholly owned, directly or indirectly,

by any one or more of the foregoing; and

(B) such entity was providing electric service to such ultimate consumer on the date of enactment of this subsection

or would utilize transmission or distribution facilities that it owns or controls to deliver all such electric energy to such

electric consumer.

Nothing in this subsection shall affect any authority of any State or local government under State law concerning the transmission of

electric energy directly to an ultimate consumer.

(i) LAWS APPLICABLE TO FEDERAL COLUMBIA RIVER TRANSMISSION SYSTEM.—(41) The Commission shall have

authority pursuant to section 210, section 211, this section, and section 213 to (A) order the Administrator of the Bonneville Power

Administration to provide transmission service and (B) establish the terms and conditions of such service. In applying such sections

to the Federal Columbia River Transmission System, the Commission shall assure that—

(i) the provisions of otherwise applicable Federal laws shall continue in full force and effect and shall continue to be

applicable to the system; and

(ii) the rates for the transmission of electric power on the system shall be governed only by such otherwise applicable

provisions of law and not by any provision of section 210, section 211, this section, or section 213, except that no rate for the

transmission of power on the system shall be unjust, unreasonable, or unduly discriminatory or preferential, as determined

by the Commission.

(2) Notwithstanding any other provision of this Act with respect to the procedures for the determination of terms and

conditions for transmission service—

(A) when the Administrator of the Bonneville Power Administration either (i) in response to a written request for

specific transmission service terms and conditions does not offer the requested terms and conditions, or (ii) proposes to

establish terms and conditions of general applicability for transmission service on the Federal Columbia River Transmission

System, then the Administrator may provide opportunity for a hearing and, in so doing, shall—

(I) give notice in the Federal Register and state in such notice the written explanation of the reasons why the

specific terms and conditions for transmission services are not being offered or are being proposed;

(II) adhere to the procedural requirements of paragraphs (1) through (3) of section 7(i) of the Pacific Northwest

Electric Power Planning and Conservation Act (16 U.S.C. 839(i) (1) through (3)), except that the hearing officer shall,

unless the hearing officer becomes unavailable to the agency, make a recommended decision to the Administrator that

states the hearing officer's findings and conclusions, and the reasons or basis thereof, on all material issues of fact, law,

or discretion presented on the record; and

(III) make a determination, setting forth the reasons for reaching any findings and conclusions which may differ

from those of the hearing officer, based on the hearing record, consideration of the hearing officer's recommended

decision, section 211 and this section, as amended by the Energy Policy Act of 1992, and the provisions of law as

preserved in this section; and

(B) if application is made to the Commission under section 211 for transmission service under terms and conditions

different than those offered by the Administrator, or following the denial of a request for transmission service by the

Administrator, and such application is filed within 60 days of the Administrator's final determination and in accordance with

Commission procedures, the Commission shall—

(i) in the event the Administrator has conducted a hearing as herein provided for (I) accord parties to the

Administrator's hearing the opportunity to offer for the Commission record materials excluded by the Administrator

from the hearing record, (II) accord such parties the opportunity to submit for the Commission record comments on

appropriate terms and conditions, (III) afford those parties the opportunity for a hearing if and to the extent that the

Commission finds the Administrator's hearing record to be inadequate to support a decision by the Commission, and

(IV) establish terms and conditions for or deny transmission service based on the Administrator's hearing record, the

Commission record, section 211 and this section, as amended by the Energy Policy Act of 1992, and the provisions of

law as preserved in this section, or

(ii) in the event the Administrator has not conducted a hearing as herein provided for, determine whether to issue

an order for transmission service in accordance with section 211 and this section, including providing the opportunity

for a hearing.

(3) Notwithstanding those provisions of section 313(b) of this Act (16 U.S.C. 825I) which designate the court in which review

may be obtained, any party to a proceeding concerning transmission service sought to be furnished by the Administrator of the

Bonneville Power Administration seeking review of an order issued by the Commission in such proceeding shall obtain a review of

such order in the United States Court of Appeals for the Pacific Northwest, as that region is defined by section 3(14) of the Pacific

Northwest Electric Power Planning and Conservation Act (16 U.S.C. 839a(14)).

(4) To the extent the Administrator of the Bonneville Power Administration cannot be required under section 211, as a result

of the Administrator's other statutory mandates, either to (A) provide transmission service to an applicant which the Commission

would otherwise order, or (B) provide such service under rates, terms, and conditions which the Commission would otherwise require,

the applicant shall not be required to provide similar transmission services to the Administrator or to provide such services under

similar rates, terms, and conditions.

(5) The Commission shall not issue any order under section 210, section 211, this section, or section 213 requiring the

Administrator of the Bonneville Power Administration to provide transmission service if such an order would impair the
182 Energy Information Administration/ The Changing Structure of the Electric Power Industry: An Update

Administrator's ability to provide such transmission service to the Administrator's power and transmission customers in the Pacific

Northwest, as that region is defined in section 3(14) of the Pacific Northwest Electric Power Planning and Conservation Act (16 U.S.C.

839a(14)), as is needed to assure adequate and reliable service to loads in that region. 

(j) EQUITABILITY WITHIN TERRITORY RESTRICTED ELECTRIC SYSTEMS.—With respect to an electric utility which is

prohibited by Federal law from being a source of power supply, either directly or through a distributor of its electric energy, outside

an area set forth in such law, no order issued under section 211 may require such electric utility (or a distributor of such electric utility)

to provide transmission services to another entity if the electric energy to be transmitted will be consumed within the area set forth

in such Federal law, unless the order is in furtherance of a sale of electric energy to that electric utility: Provided, however, That the

foregoing provision shall not apply to any area served at retail by an electric transmission system which was such a distributor on the

date of enactment of this subsection and which before October 1, 1991, gave its notice of termination under its power supply contract

with such electric utility. 

(k) ERCOT UTILITIES.—

(1) RATES.—Any order under section 211 requiring provision of transmission services in whole or in part within

ERCOT shall provide that any ERCOT utility which is not a public utility and the transmission facilities of which are

actually used for such transmission service is entitled to receive compensation based, insofar as practicable and

consistent with subsection (a), on the transmission ratemaking methodology used by the Public Utility Commission

of Texas.

(2) DEFINITIONS.—For purposes of this subsection—

(A) the term “ERCOT” means the Electric Reliability Council of Texas; and

(B) the term “ERCOT utility” means a transmitting utility which is a member of ERCOT.

(16 U.S.C. 824k)