DOE/EIA-0639

Electricity Transmission

in a Restructured Industry:

Data Needs for Public Policy Analysis

December 2004

Energy Information Administration

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 U.S. Department of Energy. The information contained herein should be attributed to the

Energy Information Administration and should not be construed as advocating or reflecting any policy position of

the Department of Energy or any other organization. Service Reports are prepared by the Energy Information

Administration upon special request and are based on assumptions specified by the requester.

Preface

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

carry out a comprehensive program that will collect,

evaluate, assemble, analyze, and disseminate data and

information relevant to energy resources, reserves, production, demand, technology, and related economic and

statistical information. This report was written in view

of those responsibilities. Federal law prohibits EIA from

advocating policy.

Douglas R. Hale (DHale@eia.doe.gov, 202 287-1801) was

the project leader for this study and the principal author

of the report. Thomas Leckey conducted much of the

research on data describing the grid’s support of

markets. He also performed important research on

the data and models relevant to reliability. Matthew

Lackey researched and compiled much of the financial and demand data contained in this report. Emily

Bartholomew of Lawrence Berkeley National Laboratory (LBNL) constructed the graphics and most of the

tables appearing in this report. LBNL staff and senior

management, particularly, Joseph Eto and Mark Levine,

contributed expertise and critical research resources to

this project.

Three Independent Expert Reviewers—Paul Joskow

(Massachusetts Institute of Technology), Karen Palmer

(Resources for the Future), and Steven Stoft (independent consultant)—and two EIA consultants—Robert

Trost and Julian Silk (George Washington University)—

provided detailed reviews of a draft version of this

report while under contract to EIA. Those reviews are

available from the author on request. E. Stanley Paul

(EIA retired) also wrote thorough reviews of versions of

the report as a public service. The report greatly benefited from the reviewers’ insightful comments and

suggestions.

In addition, a number of individuals took it upon themselves to provide critical reviews of major sections of the

report. Among those volunteers are John Kelly (American Public Power Association), Robert Thomas (Cornell

University), Bernard Lesieutre and Joseph Eto (LBNL),

Udi Helman and Thanh Luong (Federal Energy Regulatory Commission), and David Meyer (U.S. Department

of Energy). EIA reviewers included Rodney Dunn, Patrick Farace, Nancy Kirkendall, Kevin Lillis, Larry

Spancake, Phillip Tseng, Louis Demouy, Stan Kaplan,

and Susan Holte. Collectively they performed the

invaluable but thankless jobs of correcting errors of fact

and logic, identifying relevant data series, and suggesting alternative interpretations of the facts uncovered in

the course of the research. The author is indebted to

them all.

Energy Information Administration / Electricity Transmission Data iii

Contents

Page

Energy Information Administration / Electricity Transmission Data v

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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

Purpose of This Report. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Transmission Data and Industry Restructuring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Financial Performance and Investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Transmission and Wholesale Power Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Wholesale Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Conclusion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Report Organization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1. Official Transmission Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

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

Transmission Technology, Industry Organization, and Data Collection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Official Transmission Data Currently Collected. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

2. Reliability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Reliability Definitions and Indicators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Markets and Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Official Data on Reliability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Reliability Incidents, Outage Probabilities, and Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Planning Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Analytical Tools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Response to Markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Filling the Information Gaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

3. Financial Performance and Investment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

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

Measures of Financial Performance and Investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Impact of Restructuring on Relevant Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Official Transmission Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Standalone Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Transmission Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Revenues from Grid-Supplied Ancillary Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Operations and Maintenance Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Book Values of Plant and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

External Costs and Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Regional Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Utility Investment and Capital Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Independent Power Producers, Merchant Transmission, and RTO/ISO Investments . . . . . . . . . . . . . . . . . . . . 34

Filling the Information Gaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

4. Transmission and Wholesale Power Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Measuring the Grid’s Impact on Wholesale Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Data Showing the Grid’s Support of Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

New Generator Entry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Contents (Continued) Page

Tables

vi Energy Information Administration / Electricity Transmission Data

Appendix A. Federal Data Collections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Electricity Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Cost and Quality of Transmission Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Bottlenecks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Congestion Costs and Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Seams Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Economic Trade and Regional Price Differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Filling the Information Gaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

5. Wholesale Competition. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Measures of Wholesale Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Number of Competitors, Concentration Ratios, and New Entry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Price Compared to Marginal Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Withholding and Manipulation of Transmission Markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Limits on Market Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Data on Wholesale Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Number of Firms and Concentration Ratios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Price Compared to Marginal Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Entry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Demand-Price Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Filling the Information Gaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

O1. Reliability Data: Possible Changes to Existing Forms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

O2. Financial and Investment Data: Possible Changes to Existing Forms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

O3. Transmission and Wholesale Power Market Data: Possible Changes to Existing Forms. . . . . . . . . . . . . . . . . . . . 7

1. Data Collection and Reporting Hierarchies by Electrical and Political/Jurisdictional Entity. . . . . . . . . . . . . . . . 10

2. Current Federal Data Collections Related to Electricity Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

3. Transmission Data Elements and Related Collection Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

4. Data Elements for Facility and Reliability Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

5. Major Disturbances and Unusual Occurrences on the U.S. Electricity Grid, 2002 . . . . . . . . . . . . . . . . . . . . . . . . . 21

6. Base Transfers and Incremental Transfer Limits Among Selected NERC Reliability Regions

and Subregions, 2000-2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

7. Reliability Data: Possible Changes to Existing Forms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

8. Gross Volume of Wheeling in Three NERC Regions, 1993-2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

9. Gross Revenue from Wheeling in Three NERC Regions, 1993-2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

10. Total Operations and Maintenance Costs for Transmission in Three NERC Regions, 1993-2002. . . . . . . . . . . . . 34

11. Comparison of Changes in High-Voltage Transmission Infrastructure and

Electricity Generation, 1990-2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

12. Annual Capital Additions to Transmission Plant in Service, 1988-2002. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

13. Financial and Investment Data: Possible Changes to Existing Forms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

14. Non-firm Point-to-Point Transmission Service Provided by Entergy in June 2003 . . . . . . . . . . . . . . . . . . . . . . . . 41

15. New Generating Capacity Added by Type of Ownership, 1995-2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

16. Entergy Transmission Service Rates as of June 1, 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

17. Major Bottlenecks in Five ISO/RTO Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

18. Estimated Project Costs for Partial Relief of Congestion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

19. Summary of Congestion Costs Reported by ISOs and FERC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

20. Wholesale Electricity Trade (Sales for Resale), 1990-2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

21. Spot Market Sales as a Percentage of Total Demand, 1999-2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

22. Comparison of Electricity Transactions Reported by the U.S. Department of Energy (DOE) and

Canada’s National Energy Board (NEB), 1997-2001. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

23. Transmission and Wholesale Power Market Data: Possible Changes to Existing Forms. . . . . . . . . . . . . . . . . . . . 49

24. PJM Congested Hours (Real Time) in 2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
Figures Page

Energy Information Administration / Electricity Transmission Data vii

1. NERC Interconnections and Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

2. Independent System Operators (ISOs). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

3. NERC Regions and Control Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

4. North American Power System Outages, 1984-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

5. Level 2 or Higher Transmission Loading Relief Reports by Month, 1997-2004. . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

6. Gross Revenue from Wheeling in Three NERC Regions, 1993-2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

7. New Generating Capacity Added by NERC Region, 1995-2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

8. Price Differential and NYISO Export Volume, January-December 2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

9. Average PJM Hourly Wholesale Price on July 16, 2002. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Overview

Introduction

Federal law and implementing regulations are causing

the most significant change in the U.S. electric power

industry since the Great Depression. For more than 60

years the industry was characterized by a structure—

utilities serving exclusive franchises—and a regulatory

strategy—pricing at average prudent cost of service—

that are now changing in fundamental ways.

Beginning with the Public Utility Regulatory Policies

Act of 1978 (PURPA), and continuing with the Energy

Policy Act of 1992 (EPACT), Congress allowed certain

kinds of generators to enter wholesale power markets.

In 1996, the Federal Energy Regulatory Commission

(FERC) issued Order 888 requiring:

. . . all public utilities that own, control or operate facilities used for transmitting electric energy in interstate

commerce to have on file open access non-discriminatory transmission tariffs that contain minimum terms

and conditions of non-discriminatory service . . . .1

The Order “unbundled” electrical energy generation

from transmission and other services needed to deliver

power to customers.2

FERC’s intent was that its own administrative determination of the cost of service would eventually be

replaced by competitive markets as the arbiter of just

and reasonable rates for wholesale energy and any services that could be supplied competitively. As FERC

explained, Order 888 is necessary because:

The only way to effectuate competitive markets and remedy discrimination is through readily available, nondiscriminatory transmission access.3

Transmission, however, would remain regulated.4 An

exception is that the rates charged by “merchant” transmission projects would not be regulated.5 Efforts by

FERC and the States to bring competition to the electric

power industry are collectively referred to as restructuring. In response to Order 888 and other FERC initiatives,

the industry has seen a huge increase in the number of

independent generators seeking transmission services.

Recently the U.S. Department of Energy (DOE), FERC,

and the U.S. Congress have questioned whether the

high-voltage transmission system is capable of supporting its growing economic role.6 In May 2001, the

National Energy Policy Development (NEPD) Group,

referring to the transmission system as the “highway

system for interstate commerce in electricity,” recommended that reliability standards be made mandatory,

in part because of the increasingly competitive nature of

the electricity market.7

In May 2002, DOE’s National Transmission Grid Study

called attention to the physical capability of the transmission infrastructure by finding:

Energy Information Administration / Electricity Transmission Data 1

1Federal Energy Regulatory Commission, “Recovery of Stranded Costs by Public Utilities and Transmitting Utilities,” Order No. 888,

Final Rule (April 24, 1996), Summary.

2Order 888 also identified a number of ancillary services that were considered, from a regulatory point of view, to be part of transmission

service and thus subject to regulatory oversight and the potential for market pricing. These ancillary services include voltage regulation,

operating reserves, and balancing energy. The companion Order 889 required transmission providers to post their available transmission

capability (ATC) on Internet sites, collectively called the Open Access Same-Time Information System (OASIS).

3Federal Energy Regulatory Commission, “Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission

Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities,” Order No. 888-A, Docket Nos.

RM95-8-001 and RM94-7-002 (March 4, 1997), p. 11.

4The high-voltage transmission grid is almost universally viewed as a natural monopoly. Without a grid operator to balance power supply and demand at all times, maintain voltage, and ensure that lines are not overloaded, the grid could not operate. The operator accomplishes this by such means as requiring generators to adjust their output to protect the system, opening and closing circuits, and limiting net

imports. The grid operator, therefore, has enormous influence over the availability and price of transmission. This power is neither tempered by competition from other networks nor influenced by the threat that most users might leave the grid. Consequently, transmission is

regulated virtually everywhere.

5A merchant transmission firm directly charges users of its lines for their use. It does not recover its fixed costs through regulated rates.

6In 2002 the high-voltage electrical grid consisted of more than 157,000 miles of high-voltage power lines (230 kilovolts and above) connecting generators to bulk power consumers (North American Electric Reliability Council, Reliability Assessment 2002-2011, October 2002,

Table 3, p. 22). At times government and industry define high-voltage lines as starting at 69 or 138 kilovolts. Bulk power customers include

large industrial and commercial facilities, governments, cooperatives, traders, and distribution companies that buy power at wholesale.

Distribution companies supply mostly retail customers at low voltage.

7U.S. Department of Energy, National Energy Policy Development Group, Reliable, Affordable, and Environmentally Sound Energy for America’s Future (Washington, DC, May 2001).
There is growing evidence that the U.S. transmission

system is in urgent need of modernization. The system

has become congested because growth in electricity

demand and investment in new generation facilities

have not been matched by investment in new transmission facilities . . . .8

Similarly, in July 2002 FERC called attention to both

transmission infrastructure and markets in concluding:

[There are]... persistent and costly problems in the

nation’s wholesale electric power markets. These include

a decade of under-investment in needed transmission,

generation siting in locations far from customers,

unduly discriminatory behavior by transmission providers. . . and fundamental design flaws in certain existing electricity markets . . . .9

Less well recognized is the impact of the industry’s

structural change on the data supporting public policy.

When there is a fundamental change in the way an

industry does business, as is now happening in electricity, the basic data needed to describe the industry also

change. Federal agencies charged with collecting industry data may need to modify their data collection methods and, as needed, acquire new kinds of data. The

agencies must also develop new ways of aggregating

and disaggregating basic reports to accommodate new

organizational and market boundaries.

The Federal Energy Administration Act of 1974 (P.L.

93-275, 15 U.S.C. 761 et seq.) and the DOE Organization

Act (P.L. 95-91, 42 U.S.C. 7101 et seq.) require the Energy

Information Administration (EIA) to carry out a centralized, comprehensive, and unified energy information

program to collect, evaluate, assemble, analyze, and disseminate information on energy resource reserves, production, demand, technology, and related economic and

statistical information for use in assessing the adequacy

of energy resources to meet near-term and longer term

domestic demands and to inform public policymakers.

FERC is responsible for regulating the wholesale power

market and the high-voltage transmission system that

supports interstate trade. Together, FERC and EIA are

the major Federal Government sources of transmission

information.

The changing structure of the industry and the Federal

Government’s increasing interest in transmission have

prompted EIA to reexamine current official data collections to determine whether they continue to meet the

needs of the Government.10

Purpose of This Report

One purpose of this report is to examine how well existing official data serve the function of informing Federal

policymakers about electric power transmission in interstate commerce. Official data are those produced by the

Federal and State governments, their agents, and regulated entities such as Independent System Operators

(ISOs). Data that are routinely supplied to DOE, EIA, and

FERC by the North American Electric Reliability Council (NERC) are also included.

A second purpose of this report is to determine whether

currently unavailable data could in fact be obtained.

Before any agency of the Federal Government can collect

or continue to collect data from 10 or more persons, it

must obtain approval from the Office of Management

and Budget (OMB). Two minimum thresholds for OMB

approval of an agency’s data collection are that the data

are needed for the Federal Government’s legitimate purposes, and that the data can in fact be obtained. Those

thresholds are the focus of this report.

Regarding OMB’s first threshold, the Federal Government needs data and models to answer factual questions

basic to resolving long-standing public policy issues.

This report identifies transmission information relevant

to three broad national policy interests:

• Reliability11 and national security

• Economic regulation

• Economic growth and efficiency.12

The Federal Government’s role in reliability management has been to monitor outages and require investor-owned utilities (IOUs) to show that their plans are

2 Energy Information Administration / Electricity Transmission Data

8U.S. Department of Energy, National Transmission Grid Study (Washington, DC, May 2002), p. xi.

9Federal Energy Regulatory Commission, “Commission Proposes New Foundation for Bulk Power Markets With Clear, Standardized

Rules and Vigilant Oversight,” News Release (July 31, 2002), Docket No. RM01-12-000.

10EIA has also sponsored focus groups of data suppliers and users to determine their needs and constraints in supplying transmission

data.

11Reliability is defined here as the degree of performance of the elements of the bulk electric system that results in electricity being delivered to customers within accepted standards and in the amount desired. For more discussion on the concept of reliability, see Chapter 2.

12The East Coast blackout of 1965 and subsequent blackouts in the western United States, the terrorist attacks of September 11, 2001, and

the August 14, 2003, East Coast blackout showed the national interest in a reliable, secure transmission grid. The Federal Government’s substantial involvement in regulating and in building interstate power transmission and generation goes back to the start of the New Deal. The

Federal Power Act of 1935 authorized the Federal Power Commission (now FERC) to regulate utilities involved in interstate transmission

and power sales to ensure “just and reasonable” electricity prices. In 1933, the Federal Government chartered the Tennessee Valley Authority to build hydroelectric facilities to promote regional economic development.
consistent with reliable operations.13 DOE also sponsors

reliability research, conducts investigations after major

outages, and works with industry reliability groups to

anticipate reliability problems.14 The Federal Government does not determine acceptable levels of reliability,

nor does it mandate how reliable performance is to be

obtained. That is left to the industry—particularly,

NERC.

Since the September 11, 2001, terrorist attacks, the Federal Government has restricted access to certain grid

data that were previously available to the public. The

data needed to analyze reliability are a crucial part of the

information needed to identify the grid’s vulnerabilities

to physical attack. Whether the terrorist threat will cause

the Government to take a more direct role in reliability

modeling, analysis, and management is an open question. If it does, the Government’s data requirements will

only grow.

FERC is charged with ensuring just and reasonable

prices for power in interstate commerce. In addition,

State regulators continue to be deeply involved in transmission regulation. They effectively regulate transmission costs and prices for “internal transactions” and also

control siting and eminent domain.

FERC has long collected data on capital and operating

costs from IOUs. FERC uses the information to ensure

that tariffs for wholesale electricity sales bear a reasonable relation to costs. EIA complements the FERC collections with less detailed reports from other generation

and transmission owners to produce industry-wide

totals.

For almost a decade FERC has been attempting to create

competitive wholesale electricity markets by opening

the Nation’s electricity transmission grid to competing

generators, by promoting regional transmission markets, and by encouraging investment in transmission

capability.15 If its policy initiatives succeed, FERC would

transform large areas of the country into “common markets” for electricity commerce. The transmission grid

would become a network of superhighways for markets,

seamlessly moving power across the country to reduce

costs and improve reliability. FERC would then be in a

position to use markets as the primary means of deciding whether wholesale prices are “just and reasonable.”

The Federal Government is also responsible for approving utility mergers and for enforcing antitrust law, as

well as wire fraud and conspiracy statutes incident to

recent prosecutions for electricity market manipulation.

The data examined in this report are those needed to

address factual questions of policy interest, including

the following:

• How reliable is the grid? Is reliability improving or

deteriorating?

• How much does transmission cost? What are the

revenues, prices, and returns of transmission? How

do costs, prices, and returns compare regionally?

• What investments are being made to expand, maintain, and modernize the grid?

• Is the grid accommodating economic trade? Is the

grid available to all competitors (i.e., is there open

access)? How much do customers and generators

pay for transmission? What is the quality of transmission service?

• Are markets for wholesale electricity competitive?

Is the grid being used to shield firms from

competition?

Regarding OMB’s second threshold, this report indicates that currently unmet data needs might be satisfied

by one of three means: by modifying existing data collections, by coordinating and consolidating information

from official and quasi-official entities, or by undertaking new data collections. It shows that, in principle, the

needed data can be obtained; however, the suggestions

do not represent the only or necessarily the best ways of

obtaining transmission data.

Any significant change in official transmission data

would require long-term coordinated effort across EIA,

FERC, DOE, and OMB. In reviewing any specific proposal, OMB would consider more than the policy relevance of the data and whether it could be collected. (For

example, EIA’s fiscal year 2005 budget does not include

funding for the Form EIA-412 survey, which collects

Energy Information Administration / Electricity Transmission Data 3

13Form EIA-417 collects data on outages and power quality problems. Form EIA-411 and FERC Form 715 collect facility and electrical

data needed for reliability studies.

14DOE plays a major role in investigating large-area reliability failures, as discussed in Chapter 3. See, for example, U.S.-Canada Power

System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations (Washington, DC, April 2004), web site https://reports.energy.gov/BlackoutFinal-Web.pdf. The Department’s Office of Electricity Transmission and

Distribution also sponsors a wide-ranging program of research into technologies to improve reliability and better manage the grid. See web

site http://electricity.doe.gov.

15See Federal Energy Regulatory Commission, Promoting Wholesale Competition through Open Access Nondiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, Final Rule, 18 CFR Parts 35 and

385 (April 24, 1996); Regional Transmission Organizations, Order No. 2000, Final Rule, 18 CFR Part 35 (January 6, 2000); Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design, Notice of Proposed Rulemaking, 18 CFR Part 35,

Docket No. RM01-12-000 (Washington, DC, July 31, 2002); and Proposed Pricing Policy for Efficient Operation and Expansion of Transmission

Grid, Notice of Proposed Rulemaking, 18 CFR Part 35, Docket No. PL03-1-000 (Washington, DC, January 15, 2003).
data from public power and municipal systems, including transmission-related information.) OMB would also

consider public comments, whether the data are available elsewhere, the likely quality of the data, the cost of

collection, the burden on the public, and whether the

data should be confidential. Those issues are not considered in this report.16 This report, therefore, neither advocates nor commits the Federal Government to the

collection of specific data elements in the future.

Transmission Data and

Industry Restructuring

Official data collections were designed in the context of

electricity markets based on cost of service, dominated

by utilities that served exclusive franchises. Relative to

generation, transmission was cheap. Utilities built whatever transmission they needed to serve their customers,

and few relied on power from distant suppliers to meet

their customers’ needs. In that world, transmission was

not a focus of policy attention.

The Federal Government collects a great deal of information about transmission, much of which is predicated

on an industrial structure that no longer exists. Many

gaps in transmission data discussed in this report have

come about because restructuring is changing the structure of the electric power industry.

For the limited purposes of this report, the basic elements of a restructured market can be characterized as

follows:

• Energy, reserves, transmission and various services

are unbundled and separately priced. Transmission

is to be a standalone enterprise.

• The grid and wholesale markets are open to

competitors.

• Markets are used to price wholesale energy and,

when possible, related services.

• Transmission tariffs are regional, based on regional

capital recovery and operating costs.

• Additional charges associated with using fully

loaded lines—i.e., congestion charges—provide signals for transmission use, generator siting, and grid

expansion. Congestion charges are based on market

prices.17

• Grid expansion projects are based on regional plans.

The scope and pace of restructuring have been uneven

across the United States, and as yet no part of the country is “fully restructured.” Currently, industry participants operate in one of three distinct economic and

regulatory systems:

• ISOs in the Northeast and California are operating

restructured public markets under formal agreements with FERC, but each ISO has taken a different

approach to restructuring.

• Public power systems, cooperatives, municipal systems, and most of Texas (ERCOT) operate outside of

FERC jurisdiction in most respects. In Texas, ERCOT

operates its own market.

• The remainder of the industry is operating in

FERC-regulated, private markets that have not been

restructured.

In much of the country electricity is unbundled, the grid

is at least partially open to competitors, and markets are

being used to price wholesale energy. Except for the

Midwest ISO, the ISOs have auction markets with publicly reported wholesale market prices. They differ in

their operating procedures and the details of their markets. The majority of the country, however, depends on

bilateral agreements made in private markets, and

wholesale prices are not public. In most of the country

transmission rates are not regional, there are no separate

congestion charges, and regional planning is limited.

Findings

Reliability

With restructuring, some electric utilities have divested

generation. All are seeing power flow across utility and

regional boundaries in response to commercial opportunities. That development, together with the entry of

independent generators supplying local and distant

markets, means reliability is increasingly dependent on

the building of new transmission capability and the

management of existing capability across expanding

areas.

Data collections that the Federal Government relies on

to monitor reliability have not kept pace with the ascendancy of transmission in a restructuring industry. The

Government does not have the electrical models (power

flow models) and data necessary to verify that existing

and planned transmission capability is adequate to keep

the lights on. The industry’s reported plans for assuring

4 Energy Information Administration / Electricity Transmission Data

16The availability and quality of privately collected data vary over time, depending to some extent on what official sources choose to collect and release. Data quality, costs, burden, confidentiality, and similar attributes can only be evaluated relative to a specific collection proposal at a particular time.

17Congestion costs and revenues and system redispatch costs all arise from limits on the transmission grid. They are discussed in

Chapter 4.
reliable operation in the future are not necessarily those

analyzed in the power flow analyses that industry does

submit to FERC. Investment in the high-voltage grid for

metering, monitoring, communications, software, and

computation is unknown. Neither the industry nor the

Government has data adequate to allow rigorous

cost-benefit analyses of transmission-related investments to enhance reliability.

Much improvement in the Government’s ability to oversee reliability could be achieved by modifying existing

data collections, as shown in Table O1. The forms referenced in Table O1 are described in Chapter 1.

Financial Performance and Investment

FERC collects capital and operating cost data from IOUs

as part of its responsibility to ensure just and reasonable

electricity prices. EIA and the U.S. Department of Agriculture’s Rural Utilities Service (RUS) complement the

FERC collections with less detailed reports from the

other generation and transmission owners to produce

industry-wide totals. FERC’s Commissioners are concerned with the economics of transmission as a

standalone enterprise because of their obligation to

ensure just and reasonable prices in a restructuring environment. But FERC’s financial accounts are more appropriate to the circumstances of integrated regulated

utilities selling bundled electricity in a cost-of-service

environment.

Apart from a few “transmission only” entities, FERC

Form 1 says little about the economics of transmission.

Official data do not capture transmission’s financial performance, in large part because most transmission revenue is bundled with revenue from retail sales and is not

separately identifiable.

If transmission were fully unbundled, its revenues

would be unambiguous. Absent that, FERC could

require line-of-business reporting—a fundamental

change that would be tantamount to introducing a new

data collection form. How useful or valid the resulting

estimates would be is a serious question.

Far less dramatic changes to FERC Form 1, Form EIA412, and Form EIA-860 would make the data more useful for cost and investment (but not financial) analysis.

Precise definitions of transmission would be a logical

place to start. The available data describing transmission

operation costs, capital stock, and investment are not

comparable across reporters, because neither FERC

Form 1 nor Form EIA-412 imposes a common definition

separating transmission from distribution.

The “investment” series derived from official data are

flawed in at least three other ways. First, additions to

transmission plant and equipment reflect not only new

investment but also purchases of existing assets from

others, land purchases, and other expenditures that,

while relevant for some purposes, are not “investment”

Energy Information Administration / Electricity Transmission Data 5

Table O1. Reliability Data: Possible Changes to Existing Forms

Information Need Form Needed Changes Comment

1. High-quality power

flow models of

existing and

planned systems.

FERC 715 1. Identify load buses by MSA.a

2. Add selected power flow cases of existing system.

3. Model planning data for 1, 3, and 5 years in future.

4. Provide contingency lists.

5. Explain line and voltage violations.

The quality of reporting is uneven.

Submissions often do not use

EIA/EPA names and contain serious

electrical violations.

2. Data on the recent

adequacy, security

status of control

areas. Data to

verify power flow

models of existing

system.

FERC 714 1. Actual hourly demand, generation, inter-control-area

power flows experienced in control regions for selected

715 cases (2 above).

2. Experienced line and voltage violations.

3. Use EIA/EPA generator names and same line/bus

identifiers as on FERC Form 715.

3. A consistent set of

reference reliability

plans.

FERC 714,

EIA-411,

EIA-860

1. Require Forms EIA-411 and EIA-860 data to describe

the same plan.

2. Require FERC Form 714 (Part 111, Schedule 2) and

Form EIA-411 demand projections to be consistent.

These plans should be the basis for

the power flow analyses 1, 3, and 5

years into the future.

4. Monitor potential

demand response.

EIA-861 Add a schedule showing annual total megawatthours

metered hourly (or higher frequency) and megawatthours

billed by time of consumption.

To quantify extent of price responsive

demand (see Chapter 5).

5. Investment in

metering and

control of the

high-voltage grid .

FERC 1,

EIA-412

1. Adopt NIPA definition of investment.

2. Report investment in metering, communication, software,

and control of the high-voltage grid.

See Chapter 2.

a

MSA stands for Metropolitan Statistical Area. An MSA is a geographic entity defined by the U.S. Office of Management and Budget. Qualification

as an MSA requires the presence of a city with 50,000 or more inhabitants, or the presence of an Urbanized Area (UA) and a total population of at least

100,000 (75,000 in New England).
in the sense of the National Income and Product

Accounts (NIPA).18 The EIA forms that are modeled

after FERC Form 1 share those attributes. Second, EIA,

unlike FERC, collects financial data on a fiscal year basis

rather than a calendar year basis. Consequently, EIA and

FERC investment and other financial data cannot be

added to arrive at a valid national total. Third, official

data do not appear to capture investment in the grid by

new market participants: merchant transmission companies and independent power producers.

Official financial statistics are not informative about

transmission revenues and costs, such as ancillary service and redispatch costs, that restructuring makes visible in prices. As ISOs and Regional Transmission

Organizations (RTOs) become more prominent, it will

be increasingly important to allocate transmission costs

to particular organizations. The kinds of changes to

existing forms that would be required are shown in

Table O2.

Transmission and Wholesale Power

Markets

Much of the data needed to evaluate the grid’s support

of markets is already being collected. EIA collects comprehensive data on generators, including those planning

to connect to the grid. Those data are indispensable for

analyzing the potential supply of electricity and the

entry of generators to the market, and for calculating

market shares. FERC’s Open Access Same-Time

Information System (OASIS) contains data critical to

evaluating access, transmission tariffs, and the quality of

service. NERC has data on power flows across the highvoltage grid and on curtailments of transmission service. The ISOs are reporting congestion.

The data are not, however, available for policy analyses.

NERC’s power flow and curtailment data are not routinely available for use in assessing how transmission

constraints affect wholesale power markets. Consolidating, editing, and archiving in a single database all the

data that are required to be on individual OASIS sites

would substantially improve the Government’s ability

to evaluate the progress of restructuring, as shown in

Table O3.

Outside the ISOs, spot market prices and associated

quantities, including interregional trade flows, are not

available. FERC’s new Electric Quarterly Report (EQR)

does record transaction prices and quantities for “long

term” and “short term” transactions, but they are not the

same as the spot market prices reported by the ISOs. It is

too early to know whether the EQR data can yield accurate estimates of market prices comparable to those in

the ISOs. If not, a new collection would be required to

obtain wholesale prices and associated quantities. Significant research and effort would be required in order

to collect the information. DOE and the Canadian

government both report annual volumes of trade flows

6 Energy Information Administration / Electricity Transmission Data

Table O2. Financial and Investment Data: Possible Changes to Existing Forms

Information Need Form Needed Changes Comment

1. Consistent

separation of

transmission

from distribution

accounts.

FERC 1,

EIA-412

Explicitly define transmission in the same way for all utilities

and use that definition in assigning costs, revenues, and

net capital.

Current data are an “apples and

oranges” mix.

2. Utility investment in

the high-voltage

grid.

FERC 1,

EIA-412

1. Adopt NIPA definition of investment.

2. Report line and associated equipment investment

by voltage level.

3. Report investment in metering, communication, software,

and control of the high-voltage grid.

Current “additions to plant and

equipment” data have very limited use

for economic and reliability analysis,

although they are important to capital

cost recovery.

3. Independent power

producer (IPP)

investment.

EIA-860 Collect direct connection and grid reinforcement costs from

IPPs on EIA 860.

Some of these investments may not

be picked up on FERC Form 1. See

Chapters 3 and 4.

4. Merchant

transmission

investment.

EIA-412 Add to the list of respondents and require them to report

transmission investments, as defined above, and to fill out

Schedules 10 and 11.

Merchant investment and line data are

not currently collected.

5. Ancillary service

revenues.

FERC 1,

EIA-412

Require reporting as proposed by FERC.

6. Re-dispatch costs. FERC 1,

EIA-412

Require reporting. Only applicable to utilities owning

generators. Not necessary for ISOs.

7. Regional costs. FERC 1,

EIA-412

Require reporters to disaggregate cost, revenue, net capital

stock, and investment by appropriate region.

This would allow regional cost

comparisons.

8. Consistent

aggregation.

EIA-412 Adopt FERC definitions (see above) and require reporting

by calendar year.

EIA currently allows reporting by fiscal

year.

18The National Income and Product Accounts, maintained by the Bureau of Economic Analysis, U.S. Department of Commerce, provide

an aggregate view of the final uses of the Nation’s output and the income derived from its production. For more information see web site

www.bea.doc.gov.
between the United States and Canada. Estimated net

volumes differ by about 10 percent, and the directions of

year-to-year changes in net flows sometimes differ. EIA

and DOE are working to resolve the differences.

Wholesale Competition

The ISOs have all the data needed to assess competition

within their areas, but outside the ISOs the Government

does not have the data necessary to monitor and evaluate the competitive status of wholesale markets. Government can subpoena data in response to clear evidence of

anticompetitive behavior or as part of a merger

approval, but the subpoena is not a reasonable means of

obtaining data for ongoing market monitoring.

If Federal regulators and antitrust officials are satisfied

with market share analyses, then the critical need is for

high-quality power flow models to delineate market

boundaries. That could be accomplished with power

flow models developed for evaluating industry’s reliability plans. If Federal regulators and antitrust officials

require analyses of cost-price ratios (Lerner indices) for

non-ISO areas, price/quantity data, and other currently

unavailable data would be needed.

Conclusion

As markets for energy develop, the grid’s economics

and operations are becoming more integrated. Prices,

supplies, and reliability are not as closely associated

with individual firms as in the past. Neither power flows

nor markets begin and end at ownership and jurisdictional borders, and even if they did, individual companies and system operators rarely have complete

information on topics of policy interest. Federal and

State policymakers are forced to look beyond individual

company reports and political boundaries to inform

their oversight of the grid.

Changing and consolidating existing data collections

could greatly enhance the data available to Federal and

State policymakers. As mentioned above, the changes

would require long-term, coordinated effort across

FERC, EIA, DOE, OMB, ISOs, and perhaps NERC.

New collections would be useful to describe wholesale

prices and trade flows, congestion, regional costs

and revenues, and interconnection-wide reliability

management. However, the reality is that new collections often are controversial and have long gestations.

Report Organization

This report is organized in five chapters. Chapter 1 enumerates and describes current Federal transmission data

collection and identifies some of the data elements available from NERC and the ISOs. The other chapters

review information that can be used for describing and

analyzing transmission as it relates to reliability, regulation, and economic growth.

Chapter 2 begins by noting that the Federal Government’s role in reliability management has been to monitor outages and require IOUs to show that their plans are

consistent with reliable operations. The Government

requires data to identify reliability trends and emerging

problems. The complexity of electricity transmission’s

role in reliability means that electrical models are necessary to interpret the reliability consequences of trends

revealed in the data and of changes in the grid’s configuration. Because data series alone can say very little about

reliability, policy analysis and formulation are particularly challenging.

Energy Information Administration / Electricity Transmission Data 7

Table O3. Transmission and Wholesale Power Market Data: Possible Changes to Existing Forms

Information Need Form Needed Changes Comment

1. Access time series

data by provider.

OASIS Consolidate, edit, and archive all data required on OASIS

in a single database.

2. Transmission

service offerings

and actual rates.

OASIS As above.

3. Cost and time

required for

generator

connection.

EIA-860 Report how much generator paid for grid reinforcements,

direct (other) connection costs, and the date of the initial

connection request.

For newly activated generators, add

questions to Schedule 3, Part B,

Line 4.

4. Load-serving entity

cost and quality of

transmission

service.

EIA-861 Report percent of supply covered by long-term contracts,

percent covered by firm service (or financial transmission

rights), transmission service expense, and curtailments

(megawatthours) of firm and non-firm service in past year.

Schedule 2, Part B.

5. Generator cost

and quality of

transmission

service.

EIA-906 Report paralleling that of load-serving entities (see above).

6. Congestion costs,

trade flows and

price differentials.

ISO

web sites

ISOs define data elements the same way across ISOs and

report data to FERC.

None of this information is available

for analyzing the effect of restructuring

policy outside the ISOs.
The Federal Government, through FERC, will continue

to regulate interstate transmission and wholesale prices

for the foreseeable future. Chapter 3 focuses on the

impact of unbundling on the usefulness of existing

financial data collections. Industry unbundling has not

been accompanied by unbundling of financial records,

all but precluding financial analysis of transmission

entities.

As mentioned above, open access to transmission is key

to FERC’s policies aimed at bringing competition to the

wholesale power industry. Chapter 4 reviews the data

available for assessing the grid’s support of open, more

competitive markets. Data are relevant to answering

questions such as: Are suppliers able to access and connect to the grid? Are the costs and quality of transmission service nondiscriminatory and reasonable? Is

power readily flowing from areas with low prices to

those with high prices? Are FERC’s policy initiatives

succeeding?

The available data are only evidence that the grid is (or is

not) being used in ways that are more (or less) consistent

with expanding markets and competition. They are not

absolute measures of the size of markets or the trade

possibilities defined by the grid.

Chapter 5 considers the data available for assessing

competition in wholesale markets. The Federal Government is responsible for enforcing antitrust law as well as

wire fraud and conspiracy statutes that typically are violated in cases of market manipulation. In the context of

FERC’s standardized transmission tariff, competitive

prices are critical to congestion pricing. If wholesale

prices are not competitive, then the economic appeal of

using locational prices to manage and pay for congestion is diminished, and transmission expansion decisions may be distorted. The ISOs have substantial

information for assessing wholesale competition; outside the ISOs there is little available in the way of useful

data.

8 Energy Information Administration / Electricity Transmission Data
1. Official Transmission Data

Introduction

This chapter describes official data pertaining to electricity transmission. The following definition of “official

data” is used here: information produced by Federal and

State governments or their agents or by regulated entities, such as ISOs, and some data produced by NERC.

The sources of Federal transmission data are DOE—primarily EIA and FERC—and the RUS. Only the data from

NERC that are routinely and readily supplied to DOE,

EIA, and FERC are treated as official data.

Transmission Technology, Industry

Organization, and Data Collection

Transmitting electricity over long distances is not new.

As early as 1893, a hydroelectric generation plant was

transmitting alternating current (AC) electricity over a

10-kilovolt (kV) line from San Antonio Creek, California,

more than 40 miles to San Bernardino, California.19 That

type of line was not typically connected to lines owned

by other generating companies, but by the late 1920s

utilities realized that connecting to neighboring systems

had economic benefits. Because of different patterns of

peak loads and plant outage times in adjacent systems,

interconnections permitted significant reductions in

total installed capacity without reducing overall service

reliability.

Even before World War II, improvements in transmission technology—especially high-voltage transmission

lines—permitted electricity to be shipped economically

over hundreds of miles. In 1936, for example, the Tennessee Valley Authority built a 230-mile, high-voltage

(154 kV) line linking Norris Dam near Knoxville, Tennessee, with Wilson Dam at Muscle Shoals, Alabama.20

This capability encouraged more utilities to interconnect. Following the East Coast blackout of 1965, utilities

banded together and, in 1968, formed NERC to promote

reliability of the transmission grid. The Federal Government promoted utility interconnections and regional

planning as a means to protect system reliability and

encourage economic growth.

Regional transmission planning and coordination are a

challenge, in part because of the size of the domestic

electricity industry and the variety and number of entities that own segments of the grid. For example, New

England’s grid delivers more electricity than does the

United Kingdom’s, and ownership of the U.S. grid is

spread across 240 IOUs, 2,009 public utilities, 894 cooperatives, and 9 Federal utilities. Of all electricity sales to

end-use customers, IOUs sell about 74 percent of the

total, publicly owned utilities about 16 percent, cooperatives about 9 percent, and Federal utilities the remainder.21 Each type of entity operates in a different

regulatory and economic environment, reflecting the

evolution of the transmission grid over time in response

to particular economic opportunities and common problems facing multitudes of diverse entities. Their diversity is reflected in the data.

Two Federal agencies and two Departments collect

information on electricity transmission. FERC collects

transmission data from IOUs and other entities it regulates. EIA collects similar information from entities that

are outside FERC jurisdiction: independent power producers (IPPs), cooperatives, municipal systems, Federal

power systems, and Texas. EIA also collects data from

generators under FERC jurisdiction. DOE collects data

on North American electricity flows related to trade

with Canada and Mexico, and the Department of Agriculture collects data from cooperatives that have loans

with the RUS.

Facility owners and system operators collect electrical

data at specific points on the grid—generators, substations, and customer meters—to control flows and charge

customers for using the system. Electrical control and

associated economic data are the building blocks for all

other data collections and reporting. Data collection

agencies aggregate owner and operator information up

the hierarchies of electrical control—from buses to control areas, to ISOs, NERC regions, and Interconnections.

The text box below describes the electrical hierarchy.

Government agencies generally attempt to report the

data they collect by ownership (regulatory status),

electrical control, and political subdivision. Table 1 and

the accompanying maps (Figures 1, 2, and 3) show the

Energy Information Administration / Electricity Transmission Data 9

19U.S. Bureau of Reclamation, The History of Hydropower Development in the United States (July 13, 2003), web site www.usbr.gov/power/

edu/history.

20Web site www.newdeal.feri.org/library/r39.htm.

21Energy Information Administration, “Table 1. Selected Electric Utility Data By Ownership, 2000,” web site www.eia.doe.gov/cneaf/

electricity/public/t01p01p1.html.
structure and number of the electrical control and political hierarchies. Interconnections, ISOs, NERC regions,

and States generally encompass a mix of entities with

different ownership, regulatory requirements, and

boundaries (both geographic and electrical). This organizational complexity alone makes it difficult to estimate

regional totals or to develop sharp interregional comparisons, although organizational complexity is not the

only challenge.

As electricity markets further develop and mature, the

grid’s economics and operations are becoming more

integrated. Prices, supplies, and reliability are not as

closely associated with individual firms as in the past.

Neither power flows nor markets begin and end at

ownership and jurisdictional borders; and even if they

did, individual companies and system operators rarely

have complete information on topics of policy interest.

Federal and State policymakers are forced to look

beyond individual company reports and political

boundaries to inform their oversight of the grid.

A fundamental change in the way an industry conducts

business, as is now happening in the electricity industry,

alters the basic data needed to describe that industry.

Federal agencies charged with collecting industry data

may need to modify their data collection methods, and

on occasion they need to acquire new types of data.

New methods of aggregating and disaggregating basic

10 Energy Information Administration / Electricity Transmission Data

Electrical Control Hierarchies: Definitions

Interconnection: A connected AC power grid that

operates at the same frequency in synchronization.

There are three Interconnections in the United States:

the Western Interconnection, the Eastern Interconnection, and Texas (ERCOT). AC power lines cannot

connect them, because by definition the Interconnections are not synchronized with each other. Direct

current (DC) lines can connect them, but because DC

lines are expensive and the physical separations are

often large, the links between Interconnections are

weak.

ISO: An organization approved by FERC that oversees, and can control, the operation of generators,

transmission companies, and markets within its area.

ISOs can function as super control areas to control

power flows into and out of their areas.

NERC Region: A voluntary association of interconnected transmission systems and generators that

plan, schedule, and operate jointly to ensure that system resources and procedures protect reliability.

NERC regions include multiple control areas and can

include more than one ISO.

Control Area: An electric system consisting of one or

more electric utilities capable of regulating generation to maintain a schedule of electricity flows.

Bus: Any place where wires come together or connect

equipment such as generators, transformers, capacitors, and substations to the grid.

Table 1. Data Collection and Reporting Hierarchies by Electrical and Political/Jurisdictional Entity

Electrical Entities Number Political/ Jurisdictional Entities Number

Interconnections . . . . . . . . . . . . . . . . . . . . . . 3 Countries . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

ISOs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Census Divisions . . . . . . . . . . . . . . . . . . . . . . 9

NERC Regions . . . . . . . . . . . . . . . . . . . . . . . 10 States (Contiguous). . . . . . . . . . . . . . . . . . . . 48

Control Areas. . . . . . . . . . . . . . . . . . . . . . . . . About 140 Utility Service Areas. . . . . . . . . . . . . . . . . . . . About 3,100

Source: Energy Information Administration.

Figure 1. NERC Interconnections and Regions

Source: North American Electric Reliability Council.

Figure 2. Independent System Operators (ISOs)

Source: Energy Information Administration and Midwest

ISO.
reports may also be needed to accommodate new organizational and market boundaries. Given the physical

and institutional complexity of the U.S. electricity industry and the variety of government interests in different

parts of the industry, it is not surprising that the data

required to answer relatively new questions about transmission are uneven and, in some cases, nonexistent.

Official Transmission Data

Currently Collected

The official data elements describing the existing system

relate to:

• Physical assets

• Configuration of those assets as a power delivery

system

• Performance of that system under normal and emergency conditions

• Economic data (cost, investment, and price).

Some of the data refer to generation and demand,

because transmission is meaningless without them. The

official data describing the planned system include:

• Projected additions and retirements of facilities

• Projected performance of the planned system in

meeting future needs.

Most Federal transmission data are collected on survey

forms. The Paperwork Reduction Act of 1995 (PRA)

requires each Federal agency to seek and obtain

approval from the OMB before undertaking a collection

of information directed to 10 or more persons, or continuing a collection for which a current OMB approval will

expire. Under the PRA, OMB approval for an agency to

use a given information collection instrument can last a

maximum of 3 years. For questionnaires and forms,

agencies are required to provide a public notice in the

Federal Register, requesting comments from the public

and affected agencies, 60 days before submitting the

instrument to OMB for review.

The Federal Government currently fields 11 major data

collection instruments directly relevant to electricity

Energy Information Administration / Electricity Transmission Data 11

Figure 3. NERC Regions and Control Areas

Source: North American Electric Reliability Council.
transmission. Table 2 identifies the forms and their target respondents.

NERC and the ISOs typically produce electronic reports

(often databases) on system operations as part of their

monitoring and oversight responsibilities. Those reports

are specific to the needs of the particular collecting organization and can change quickly. The ISOs and NERC

also develop market oversight reports and planning

documents, usually annually. NERC data pertain primarily to its members; ISO data mainly involve physical

and economic transactions within the boundaries of the

ISOs. Data collected and disseminated by the ISOs generally are available on ISO web sites in spreadsheet or

database format. Some ISOs provide summary reports

on much of the data collected; others simply provide

raw data. The data elements that individual ISOs collect

and make available to governments and the public vary

greatly.

NERC disseminates unique data collections, such as

“transmission loading relief” reports (TLRs) filed by

Reliability Coordinators.22 NERC also provides “reliability assessments,” based on its own data collections

and data from other sources, and makes them available

on its web site. The assessments, made at a regional

level, provide overviews of system reliability but do not

include the detailed data and analyses used by NERC to

reach judgments about reliability. In addition to its own

data, NERC also provides compilations of data from

Form EIA-411 (and additional forms not related to transmission) in its Electricity Supply & Demand Database

(ES&D). The ES&D is sold on NERC’s web site, and government entities can receive copies upon request.

Table 3 provides a summary of the transmission data

currently collected by the Federal Government and associated organizations and lists the available data elements. (Appendix A summarizes the principal Federal

transmission data collections.) In Table 3, an empty cell

indicates that there is no existing collection for that data

element and type on the associated form. The variety of

forms directly reflects the complexity of the industry

and the electrical system.

Although a particular data element (such as “voltage”)

may be collected on five different forms, that does not

mean it is being collected five times from the same

respondents. Rather, different forms may be used to collect similar data from different entities. For example,

IOUs report on FERC Form 1, and public power facilities, municipals, cooperatives, and others not reporting

to FERC report on Form EIA-412.23 Those forms essentially identify what is owned by individual companies

and other entities. Form EIA-411 associates the rated

voltages of power lines and other information with

NERC regions. FERC Form 714 collects voltage data by

control region. FERC Form 715 identifies nominal operating voltages and a host of electrical parameters by

individual line number and buses in an electrical network. Planned transmission elements are reported on

Form EIA-411 and FERC Form 715.

Several of EIA’s collections can be understood as complementing FERC collections. FERC Form 1 is the major

Federal source of data on IOU finances and facilities.

Form EIA-412 is used to collect similar data from entities

that do not report to FERC. FERC Forms 714 and 715 are

important sources of official data used for Federal

12 Energy Information Administration / Electricity Transmission Data

Table 2. Current Federal Data Collections Related to Electricity Transmission

Agency Respondents Form

FERC Investor-Owned Utilities FERC Form 1, "Annual Report of Electric Utilities, Licensees, and Others"

Control Areas FERC Form 714, "Annual Electric Control and Planning Area Report"

Investor-Owned Utilities or NERC FERC Form 715, "Annual Transmission Planning and Evaluation Report"

EIA NERC Form EIA-411, "Coordinated Bulk Power Supply Program Report"

Public and Federal Generation and

Transmission Cooperativesa Form EIA-412, "Annual Electric Industry Financial Report"

Electric Utilities Form EIA-417R, "Electric Power System Emergency Report"

Generators With More Than 1 Megawatt

of Capacity Form EIA-860, "Annual Electric Generator Report"

Industry Participants Form EIA-861, "Annual Electric Power Industry Report"

DOE Form FE-781R, "Annual Report of International Electric Import/Export Data"

RUS Electric Cooperatives: Electric

Distribution Borrowers

RUS Forms 7, "Financial and Statistical Report," and 7a, "Investments, Loan

Guarantees and Loans - Distribution"

Electric Cooperatives: Electric Power

Supply Borrowers (Forms 12a-i) and

Electric Distribution Borrowers With

Generating Facilities Forms 12d-g)

RUS Form 12, "Operating Report - Financial"

a

EIA’s fiscal year 2005 budget does not include funding for the Form EIA-412 survey.

Source: Energy Information Administration.

22A Reliability Coordinator is an individual or organization responsible for the safe and reliable operation of the interconnected transmission system for its defined area, in accordance with NERC reliability standards, regional criteria, and subregional criteria and practices.

23Because EIA’s fiscal year 2005 budget does not include funding for the Form EIA-412 survey, data previously collected on that form

will not be available for the year 2004.
Energy Information Administration / Electricity Transmission Data 13

Table 3. Transmission Data Elements and Related Collection Systems

Transmission Data Elements

Data Collection Systems

About Physical Assets About System and Performance Other

Facilities and Physical Assets

Line Data

Voltage (AC or High-Voltage DC) FERC: Form 1

EIA: Forms EIA-412 and EIA-411

FERC: Form 714 and Form 715

Line Design Information FERC: Form 1

EIA: Forms EIA-412 and EIA-411

Capability FERC: Form 715

Location (Terminals) FERC: Form 1

EIA: Forms EIA-412 and EIA-411

FERC: Form 715

Length (Miles) FERC: Form 1

EIA: Form EIA-412

RUS: Form 7 and Form 12

Ownership FERC: Form 1

EIA: Forms EIA-412 and EIA-411

FERC: Form 715

Station/Terminal Data

Name and Location FERC: Form 1

EIA: Form EIA-411

FERC: Form 715

Voltages FERC: Form 1

EIA: Form EIA-411

FERC: Form 715

Function FERC: Form 1

Load (Megavolt-Amperes) FERC: Form 1

EIA: Form EIA-412

RUS: Form 7

FERC: Form 715

Other Transmission Facilities FERC: Form 1

EIA: Forms EIA-412 and EIA-411

FERC: Form 715

Electrical Configuration

Electrical Configuration EIA: Form EIA-411 FERC: Form 714 and Form 715 ISOsa

, NERCb

Miles of Line by Voltage FERC: Form 1

EIA: Form EIA-412

RUS: Form 7 and Form 12

Control Area Interconnection FERC: Form 714

Performance

System Operating Data

System Loading FERC: Form 714 ISOsa

Transfer Capabilities ISOsa, NERCb, OATTc

Congestion (Duration) ISOsa,

Transmission Loading Relief NERCb

System Disturbances EIA: Form EIA-417 ISOsa, NERCb

Losses FERC: Form 1

EIA: Form EIA-412

RUS: Form 7 and Form 12

EIA: Form EIA-861 ISOsa

, NERCb

Economics

Cost, Price, Rate, Revenue, and Fee Data

Capital Costs: Lines and Structures FERC: Form 1

EIA: Form EIA-412

RUS: Form 7 and Form 12

System O&M Costs FERC: Form 1

EIA: Form EIA-412

RUS: Form 7 and Form 12

ISOsa

, OATTc

Balance Sheet Information FERC: Form 1

EIA: Form EIA-412

RUS: Form 7 and Form 12

Connection Costs

Transmission Service Rates ISOsa

, OATTc

Ancillary Service Rates ISOsa, OATTc

Transmission Service Revenues FERC: Form 1 ISOsa

Ancillary Service Revenues FERC: Form 1 ISOsa

Nodal Prices ISOsa

Research and Development Expenses FERC: Form 1

Transaction Datad

Interregional Transactions FERC: Form 1

EIA: Form EIA-412 and Form EIA-411

RUS: Form 7 and Form 12

EIA: Form EIA-861

FERC: Form 714

ISOsa

Intraregional Transactions FERC: Form 1

EIA: Form EIA-412

RUS: Form 7 and Form 12

EIA: Form EIA-861

FERC: Form 714

ISOsa

International Imports/Exports DOE: Form FE-781R ISOsa, NERCb

a

Data available from one ISOs are not necessarily available from another ISO; nor are the data always comparable.

b

NERC may provide access to some of the data elements in this chart that are not noted, however they are not the primary source of the data they disseminate. c

Open Access Transmission Tariffs.

d

This is not an indicator of capability but a validation that the transmission systems facilitate economic transactions.

Source: Energy Information Administration.
oversight of reliability plans, which, in the case of FERC

Form 715, includes electrical modeling of the grid. Form

EIA-411 includes both information on the “adequacy”

of existing and planned generation to meet projected

demand24 and information on new transmission

facilities that is not captured on FERC Form 714. Form

EIA-411 also includes electrical data on new lines

owned by public power companies. Form EIA-417 collects information on power outages, and DOE’s Form

FE-781R reports international power flows; neither of

these data categories is collected by FERC. Similarly, the

RUS collects detailed information on cooperatives,

which are not under FERC jurisdiction and thus do not

report data to FERC.

Three Federal collections are the major sources of official

planning data (Table 4). Most of the data are used to

demonstrate that generation resources will be adequate

to meet anticipated future demand. FERC Form 715

focuses on the ability of the transmission system to

deliver power where utility planners expect it to be

needed under anticipated peak conditions. Together,

the data from the three sources are used to assess and

monitor the reliability of power delivery in the future.

NERC and ISOs are the other major sources of transmission data. NERC typically works with its members to

assemble, verify, and submit the data collected on Form

EIA-411 and FERC Form 715. NERC also collects significant amounts of information about power flows, system

disturbances, and curtailments.25 Most of those data are

not public and are not immediately or routinely available to the Federal Government. There is no publicly

available document describing precisely what data

NERC does collect and archive.

ISOs collect and release a variety of performance data as

part of their normal operations. ISO high-frequency

(hourly) data generally refer to markets—prices, generation, imports, and exports. Although each ISO generates

vast amounts of virtually real-time operating, scheduling, planning, and bidding data, the ways in which the

data are defined, collected, formatted, and made available to the public are not consistent among the reporting

organizations. The data do not necessarily cover matching time frames, nor are the data of the same scope in

most cases. ISOs also produce a variety of reports on

their market oversight, planning processes, and planned

investments. Similar information exists outside of the

ISOs but is rarely made public. The data available to

describe transmission and related markets in most of the

United States are limited to the information collected by

the Federal Government.

Many of the suggestions that have been made for

improving the quality of data available for public policy

analysis of transmission issues involve standardizing

data that are now collected within the ISOs, extending

that standardized collection to areas outside of ISOs, and

coordinating Federal and NERC data collection efforts.

Those suggestions, as they pertain to specific aspects of

the electricity industry and the official data collection

instruments that are relevant in each case, are discussed

in detail in the remaining chapters of this report.

14 Energy Information Administration / Electricity Transmission Data

Table 4. Data Elements for Facility and Reliability

Planning

Transmission Data

Elements

Planned Data Collection

Systems

Electrical Configuration

Electrical Configuration . . . . . . . . . . EIA: Form EIA-411

FERC: Form 715

NERC

Miles of Line by Voltage. . . . . . . . . . EIA: Form EIA-411

NERC

System Operating Data

System Loading. . . . . . . . . . . . . . . . ISOs

Congestion. . . . . . . . . . . . . . . . . . . . ISOs

Line Data

Voltage. . . . . . . . . . . . . . . . . . . . . . .

AC or High-Voltage DC

EIA: Form EIA-411

and Form EIA-412

FERC: Form 715

NERC

Capability. . . . . . . . . . . . . . . . . . . . . EIA: Form EIA-411

FERC: Form 715

NERC

Location (Terminals) . . . . . . . . . . . . EIA: Form EIA-411

and Form EIA-412

FERC: Form 715

NERC

Length (Miles) . . . . . . . . . . . . . . . . . EIA: Form EIA-412

Cost . . . . . . . . . . . . . . . . . . . . . . . . . EIA: Form EIA-412

Ownership . . . . . . . . . . . . . . . . . . . . EIA: Form EIA-411

FERC: Form 715

NERC

Project In-Service Date . . . . . . . . . . EIA: EIA: Form EIA-411

and Form EIA-412

NERC

Stations/Terminals

Location . . . . . . . . . . . . . . . . . . . . . . EIA: Form EIA-411

FERC: Form 715

NERC

Voltage. . . . . . . . . . . . . . . . . . . . . . . EIA: Form EIA-411

FERC: Form 715

NERC

Function. . . . . . . . . . . . . . . . . . . . . . FERC: Form 715

Load. . . . . . . . . . . . . . . . . . . . . . . . .

Megawatts (MW),

Megavolt-Amperes Reactive (MVAr)

EIA: Form EIA-411

FERC: Form 715

NERC

Capacitors . . . . . . . . . . . . . . . . . . . .

Volt-Amperes Reactive (VAr)

FERC: Form 715

Project In-Service Date . . . . . . . . . . EIA: Form EIA-411

NERC

Source: Energy Information Administration.

24Chapter 2 discusses “adequacy” in the context of reliability.

25See, for example, “NERC Fast Links,” web site www.nerc.com.
2. Reliability

Introduction

The blackout of August 14, 2003, directly affected about

50 million people in the United States and Canada, leaving millions of them without power. Within a few

months of the blackout, the U.S.-Canada Power System

Outage Task Force identified its proximate causes.26

That analysis did not, however, address broad public

policy questions about the reliability of the electric

power system.27 Reliability refers to the power system’s

ability to deliver power of specified quality when and

where it is desired. Among the questions the Task Force

did not address are:

• How reliable is the North American electricity transmission grid?

• Is the grid becoming more or less reliable over time?

• Are necessary investments in reliability being made,

especially in transmission capability?

• Do market incentives undermine reliability? In particular, do voluntary approaches to reliability management work in a market setting?

• Are markets revealing new ways to attain reliability

at less cost?

This chapter reviews official data and analytical tools

available for answering such questions and examines

the additional types of data the Federal Government

needs to meet its reliability oversight responsibilities.

The Federal Government’s role in reliability management has been to monitor outages and require IOUs to

show that their plans are consistent with reliable operations.28 DOE also sponsors reliability research, conducts

investigations after major outages, and works with

industry reliability groups to anticipate reliability problems.29 The Federal Government does not determine

acceptable levels of reliability nor does it mandate how

reliable performance is to be obtained. That is left to the

industry, particularly NERC.

Since the September 11, 2001, terrorist attacks, the Federal Government has restricted access to certain grid

data that were previously available to the public. The

data needed to analyze reliability are a crucial part of the

information needed to identify the grid’s vulnerabilities

to physical attack. Whether the terrorist threat will cause

the government to take a more direct role in reliability

modeling, analysis, and management is an open question. If it does, the government’s data requirements will

only grow.

After the East Coast blackout of 1965, utilities formed the

NERC to develop voluntary reliability standards and

guidelines. Membership in NERC is voluntary. NERC

encouraged members in each of its 10 regions (see Chapter 1) to maintain enough reserve generation and transmission capability in their exclusive franchise (service)

areas to maintain basic service despite equipment failures and exceptionally large demand. State and Federal

regulators generally approved those investments and

permitted investors to recover their costs by charging

their captive customers. NERC also encouraged its

members to coordinate individual investment plans and

responses to reliability threats. Everyone generally

cooperated in those efforts because reliable operation

was in everyone’s best interest; no one lost customers to

lower cost competitors; and regulators underwrote their

costs.

The growth of more competitive wholesale electricity

markets since 1996, when FERC issued Order 888, has

created new challenges for reliability management. In

the past, utilities generally owned both generation and

transmission assets dedicated to serving customers in

their exclusive franchise areas. Currently, generation

and transmission assets are often owned by separate

entities and no single entity bears sole responsibility for

Energy Information Administration / Electricity Transmission Data 15

26U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and

Recommendations (Washington, DC, April 2004).

27For examples of differing views see the New York Times (August 16, 2003), p. A25: B. Richardson, “Drunk on Power,” A. Barabasi,

“We’re All on the Grid Together,” and R. Kuttner, “An Industry Trapped by a Theory.”

28Form EIA-417 collects data on outages and power quality problems. Form EIA-411 and FERC Form 715 collect facility and electrical

data needed for reliability studies.

29DOE plays a major role in investigating large-area reliability failures, as discussed in Chapter 3. See, for example, U.S.-Canada Power

System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations (Washington, DC, April 2004), web site https://reports.energy.gov/BlackoutFinal-Web.pdf. The Department’s Office of Electricity Transmission and

Distribution also sponsors a wide-ranging program of research into technologies to improve reliability and better manage the grid. See web

site http://electricity.doe.gov.
system reliability. Franchises are no longer exclusive;

wholesale customers typically can buy power from

whomever they want. Nor can regulators be counted on

to underwrite idle assets, especially those benefiting

customers in other States. Competition has also caused

power flows to cross system boundaries, and to vary in

amounts not seen before. These new operating regimes

have challenged engineers and system operators to

develop new ways of ensuring reliable operations in an

increasingly dynamic market environment.

The next section of this chapter, “Reliability Definitions

and Indicators,” discusses several reliability concepts

and identifies some of the measures these definitions

imply. Measuring reliability is akin to the problem of

measuring good health: there are a host of useful indicators but no good summary metric. Competition and the

August 14, 2003, blackout have highlighted the unstated

role of information, computation, and communications

in traditional concepts of reliability. The following section, “Markets and Reliability,” reviews some of the

effects of markets on reliability planning and management and identifies additional reliability indicators. This

is followed by a discussion of official reliability data

available to the Federal Government. The chapter concludes with suggestions on how gaps in the data might

be filled.

Reliability Definitions and Indicators

Federal interests in reliability focus on the interstate,

high-voltage power grid. State and local authorities

have jurisdiction over the lower voltage distribution system and substantial say in the building and maintenance

of the high-voltage grid. Precisely where the highvoltage grid ends and the low-voltage distribution system begins is a matter of controversy. NERC’s data and

published analysis define the high-voltage grid as 230

kV and above. For FERC Form 715 the reporting threshold for the high-voltage grid is 100 kV, but respondents

generally include lines of 69 kV and above. Form

EIA-412 defines the high-voltage system as 132 kV and

above, and Form EIA-411 uses 230 kV as the

high-voltage threshold. The differences matter because

there are large areas of the country where 69-kV and

138-kV lines deliver wholesale, bulk power. Moreover,

limits on these lines may make it impossible to fully utilize much higher voltage transmission lines. For those

reasons this report considers lines as small as 69 kV.

When the demand for power (load) differs from the

amount of generation net of losses, an AC system is

unbalanced. If the difference is large enough the system

will black out—it will fail to operate in part or in total. If

demand exceeds net generation by a lesser amount, voltage and frequency will drop, with possible damage to

equipment. Likewise, net generation in excess of

demand, but short of failure, will cause voltage and frequency to increase, again with possible damage to

equipment. Any sustained imbalance will lead to large

deviations in frequency and voltage.30 Most equipment

is designed to withstand only small departures from target voltage, frequency, and power standards. Central

control of how much power is injected and withdrawn

from the transmission grid is necessary to maintain reliable service.

Operational control is exercised mainly at the level of the

control area, ISO, and NERC reliability region. In rare

instances (such as the August 14, 2003, blackout), coordinated control across NERC regions up to the boundaries

of the relevant interconnection may be needed to prevent blackouts. Federal oversight and data collection are

focused on control areas and NERC regions.

The U.S.-Canada Task Force defined reliability as:

The degree of performance of the elements of the bulk

electric system that results in electricity being delivered

to customers within accepted standards and in the

amount desired. Reliability may be measured [emphasis added] by the frequency, duration, and magnitude

of adverse effects on the electric supply. Electric system

reliability can be addressed by considering two basic and

functional aspects of the electric system, Adequacy and

Security.31

Conceptually, the frequencies of blackouts and brownouts, their duration, size, and costs, are fundamental

measures of the grid’s historical reliability. Prospective

improvements in reliability could, in principal, be indicated by reduced probabilities of reliability problems

and reductions in their expected duration, size, and cost.

Economists argue that the level of reliability should be

set so that the marginal benefits of increased reliability

(fewer outages or power quality lapses, reduced economic loss) would equal its marginal costs (additional

generation, transmission, or better system control).32

Traditionally, each utility evaluated investment in emergency generation by comparing its cost with the cost of

16 Energy Information Administration / Electricity Transmission Data

30As mentioned in Chapter 1, the approximately 140 control areas in the United States are the basic units for balancing power flows and

maintaining power quality within their areas.

31U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and

Recommendations (Washington, DC, April 2004), p. 218.

32When investments are “lumpy,” it is not always possible to equate marginal costs and benefits.
unserved energy.33 The costs of unserved energy were

those the utilities estimated on behalf of their customers,

together with the utility’s own costs. At the level of an

individual consumer, economists have defined reliability as the proportion of the time that power of sufficient

quality costs less than the consumer is willing to pay.

When marginal benefit from the consumer’s perspective

is less than marginal cost (the price of power), the consumer does not consume—i.e., she chooses to black herself out.34

Trends in experienced and expected frequencies of

blackouts and substandard power quality would give

policymakers quantitative grounds for concluding

whether reliability is improving or deteriorating. For

reasons discussed below, neither the Federal Government nor NERC currently makes quantitative estimates

of the future probabilities of blackouts and brownouts.

Instead of quantitative measures, NERC uses a combination of expert judgment, quantitative modeling, and scenario (“what if”) analysis to assess qualitatively current

and prospective reliability across and within regions.35

NERC’s qualitative evaluation hinges on two factors:

• Adequacy—the ability of the electric system to supply aggregate electrical demand and energy requirements of customers at all times, taking into account

scheduled and reasonably expected unscheduled

outages of system elements.

• Security—the ability of the electric system to withstand sudden disruptions, such as electric short circuits or unanticipated loss of system elements.36

NERC’s focus is on whether operating practices and

physical resources within a NERC region, perhaps supplemented with emergency power imports, are sufficient to maintain electrical balance under expected and

emergency conditions. If they are, and there is a sufficient margin of safety, the system is judged reliable. This

evaluation does not establish how reliable the system is

or whether additional investments would increase reliability or be worth their cost.

Determining generator “adequacy” amounts to summing the capacities of generators within the region,

adjusting total capacity for maintenance and unplanned

outages, and comparing the total with the sum of

demand and losses less net imports. Likely and extreme

values for outages, demand, and losses are derived from

historical data. Base (net) imports and emergency

(incremental) imports appear to be derived from a

Energy Information Administration / Electricity Transmission Data 17

Transmission Anomalies

Life in an AC network

• Electrons are not transported, shipped, or otherwise moved from generators to consumers.

• Less is more and more is less—sometimes,

depending:

- Removing lines can increase delivery; increasing a line’s capability can decrease delivery.

- Increasing consumption can relieve heavily

loaded lines; decreasing consumption can

overload lines.

• Lightly loaded lines often cannot carry more

power.

• Fully loaded lines do not necessarily constrain

delivery.

Why?

• Electrons in AC systems only move back and forth

a small distance; they do not go from here to there.

• In a network there are multiple paths from generators to customers.a Electricity flows through a

network along all possible paths, following physical laws that favor those paths with “least

resistance.”

• There are no valves for directing electricity along

secure routes.

• AC electrical flow has a real and a reactive component. Only the real component transmits power,

but the total of real and reactive current determines the load on a link in the circuit.

What that means

• Power flows, voltage, and their control depend on

the details of the network’s physical configuration

and on precisely how much is being generated

and consumed at every location.

• Mathematical models are indispensable for sorting out the complexity and accurately showing

how the network can meet customers’ power

demands.

aElectricity flows along more than one path (the scheduled,

nominal, or dominant path) from a source to a load are called a

“loop flow.”

33F. Schweppe et al., Spot Pricing of Electricity (Klur Academic Publishers, 1988), pp. 137-145.

34See H. Chao and R. Wilson, “Priority Service: Pricing, Investment, and Market Organization,” American Economic Review, Vol. 77, No. 5

(December 1987), pp. 899-916.

35NERC’s summer, winter and multi-year assessments are available at website www.nerc.com.

36North American Electric Reliability Council, NERC Reliability Assessment 2002-2011: The Reliability of Bulk Electric Power Systems in

North America (October 2002), p. 7.
combination of historical experience and modeling

results. Because imports can replace the need for local

generation, the selection of base imports is important to

the generation adequacy assessment. If the comparison

shows that the amount of adjusted capacity exceeds the

amount needed with a sufficient margin of safety (usually about 15 to 20 percent of peak demand), generation

is judged adequate. NERC does not document the basis

for specific margins of safety.

Electrical models—in particular, power flow models—of the regional power system are indispensable for

determining whether the grid is “adequate” to deliver

power where needed. The input data for these power

flow models are extensive. The data include the impedance of all the branch lines in the transmission system,

the topology of the system (a statement of the connections between lines and buses), the limits of all the

branches, the voltage control capabilities of the transformers, generator capacity and availability, and

demands at individual buses. The results show the

power flowing over all the different lines, its voltage,

and whether any limits (such as thermal limits on lines)

are violated.37 Engineers rely on power flow models to

confirm that power flows under expected conditions do

not exceed the grid’s physical capabilities and operating

limits.

Engineers also need models of the region’s connected

neighbors to determine whether base imports are feasible and whether additional (incremental) imports

would be available to cover emergency imbalances. If

power from all sources can be delivered with a sufficient

margin of safety under the studied scenarios, then transmission is judged adequate.

Security analysis is concerned with the regional system’s

continued operation in the event of short circuits and

equipment (generator and line) failures. Stability analysis aims at ensuring that voltage and system synchronization are kept within limits after a short circuit.

Contingency analysis is concerned with reliable operation after generators and lines unexpectedly fail. The

hypothetical events are called contingencies; the ensemble of events is called a contingency list.38 These analyses

result in limits on “the maximum amount of electricity

that can be safely transferred over transmission lines,”39

which are imposed in adequacy analyses as if they were

physical limits.

System operators in each control area enforce security

limits by ordering generators within their systems to

adjust their output, by disconnecting users, and by

restricting the flows of power into and out of their systems. Their actions are guided by real time metering

data, computer models of their system, and experienced

judgment. Intersystem power flows are generally the

result of specific scheduling agreements between system

operators in adjoining areas. Managing power flows

across control areas can be difficult simply because

many parties must agree.

Large blackouts and brownouts of the high-voltage U.S.

grid, while not uncommon, are infrequent enough to

make statistically estimating regional probabilities and

their trends a dubious enterprise. Estimating future

probabilities based on detailed electrical descriptions of

regions, their experience of equipment failures, and similar information is conceptually possible but expensive

and of arguable accuracy.

Information relevant to indicating reliability as it relates

to transmission would include:

• Number, size, duration, and cost of blackouts and

brownouts

• Trends and status of grid adequacy and security

- Peak demand, supply and power flows by control

area

- Line outages

- Security limited lines, power curtailments, and

redispatch

• Planning data

- Projected demand

- Projected generation and transmission assets

- Power transfer capabilities

• Analytical tools

- Electrical models of regions, both as they currently exist and as described in planning

documents

- Contingency lists.

18 Energy Information Administration / Electricity Transmission Data

37Thermal limits are imposed to prevent overheating of lines due to excessive power flows. An accessible discussion of kinds of line limits can be found in U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada:

Causes and Recommendations (Washington, DC, April 2004), pp. 7-8.

38In a contingency analysis, engineers present a power flow model of the electrical system with hypothetical demand conditions and a

base case of operating generators and lines. Large generators and major lines are then taken off line one at a time to mimic unplanned outages. This is called an n-1 contingency analysis: all but 1 of the n pieces of major equipment in the electrical system are assumed to operate

normally. The analysts note those operating regimes that cause failure of other large lines, potentially resulting in cascading blackouts.

Through a planning procedure, they preclude catastrophic failures, essentially “outlawing” failed operating regimes, by de-rating vulnerable power lines. The line limits that are imposed to ensure that the system continues to operate after a failure are called n-1 limits, contingency limits, reliability limits, or some similar term. If a major piece of equipment has already failed, n-2 limits become the relevant

constraints.

39U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and

Recommendations (Washington, DC, April 2004), p. 8.
Markets and Reliability

The emergence of regional and interregional wholesale

markets has had a significant impact on the utilization of

power lines and the volatility of power flows. NERC has

stated that:

The transmission system is being subjected to flows in

magnitudes and directions that were not contemplated

when they were designed and for which there is minimal

operating experience. New flow patterns result in an

increasing number of facilities being identified as limits

to transfers . . . .40

and

. . . [O]perating experience shows that market conditions can, at times, cause volatile and unpredicted flow

patterns that cannot be reliably accommodated by the

transmission system.41

NERC has not, however, released the data and statistical

analyses underlying these conclusions.

Operators require good interregional models, precise

data, and rapid computation and communications to

manage novel and increasingly volatile power flows

successfully.42 The U.S.-Canada Task Force concluded

that three of the four basic causes for the initiation of the

August 14, 2003, blackout were related to information

technology: inadequate system understanding, inadequate situational awareness, and failure of reliability

organizations to provide effective diagnostic support.43

The task force also found that neither NERC nor the

Federal Government maintained reference models

of the directly affected regions or of the Eastern

Interconnection.

Although everyone benefits from reliable service, its

costs are borne by specific generators and transmission

owners. By bringing competition into generation and

encouraging free trade across regional markets, restructuring has reopened the question of how to pay for reliability. Free-riding beneficiaries of costly investments

have always been a feature of interconnected electrical

systems. Under regulation, utilities were assured that

they would recoup their investments; and they had no

competitors to undercut their rates. Now their investments may advantage competitors and raise their own

costs. Competitive generators cannot be faulted for their

resistance to paying for idle or underutilized assets that

benefit everyone else.

State regulators also question why citizens in their States

should pay for transmission investments that lower

costs and improve reliability for outsiders. Regulators

cannot be counted on to underwrite transmission investments, even those with significant local benefits. NERC

notes that:

With industry restructuring and the development of

regional wholesale markets, new transmission lines may

be beneficial to all parties, including the consumers of

electricity, but their costs are incurred by only one or

several entities. As a result, those entities may be reluctant to build the needed transmission facilities.44

How to pay for reliability in a competitive environment

is far from settled. The northeastern ISOs have had some

success in using markets to provide mandated reserve

generation capacity and various operating reserves;

however, no one has demonstrated a market-based way

of deciding the appropriate level of reliability and paying for it.45

To the extent that restructuring encourages demand

response to prices (and distributed generation), markets

may allow systems to operate reliably with smaller

safety margins, reducing reserves of idle equipment.

Numerous DOE studies have found that priceresponsive demand can be as important for reliability as

generation reserves: reducing demand is much like an

increase in generation of the same amount and has the

additional benefit of reducing line loadings.46 Distributed generators can potentially supply power to the grid

and meet a share of local demand, thereby directly

relieving loaded lines.

Additional information relevant to assessing reliability

in a market environment as it relates to transmission

would include:

• High-quality, interconnection-wide models

Energy Information Administration / Electricity Transmission Data 19

40North American Electric Reliability Council, NERC Reliability Assessment 2002-2011: The Reliability of Bulk Electric Power Systems in

North America (October 2002), p. 20.

41North American Electric Reliability Council, 2003 Summer Assessment: Reliability of the Bulk Electricity Supply in North America, p. 8.

42Another alternative is to increase safety margins. That would require more investment in transmission assets and lead to higher

redispatch costs.

43U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and

Recommendations (Washington, DC, April 2004), pp. 18-19.

44North American Electric Reliability Council, NERC Reliability Assessment 2002-2011: The Reliability of Bulk Electric Power Systems in

North America (October 2002), p. 28.

45Academic economists have proposed market mechanisms for determining reliability and paying for it. See H. Chao and R. Wilson,

“Priority Service: Pricing, Investment, and Market Organization,” American Economic Review, Vol. 77, No. 5 (December 1987), pp. 899-916.

46Oak Ridge National Laboratory, Load as a Reliability Resource in Restructured Electricity Markets, ORNL/TM2001/97 (June 1, 2002). See

also C. Goldman, G. Barbose, and J. Eto, “California Customer Load Reductions during the Electricity Crisis: Did they Help to Keep the

Lights On?,” Journal of Industry, Competition and Trade, Vol. 2, No. 1-2 (2002), pp. 113-142.
• Actual investment in the high-voltage grid, including specific investments in instrumentation, communications, computation, and control

• Usage (MWh) metered to permit real-time priceresponsive demand and MWh billed under real-time

pricing.

Credible interconnection models are necessary to manage reliability with increasing and novel interregional

commercial power flows. Trends in investment in the

high-voltage grid, together with information on who is

paying for it, would complement planning projections

and give policymakers a factual basis for reconsidering

how to pay for reliability investments. Investment data

showing investment in instrumentation, computation,

and control would be consistent with operators gaining

more control over the grid. Increased information and

more precise control should allow for smaller safety

margins in future reliability assessments. Price-responsive demand would be one more tool operators could

use to balance demand and supply. That could make it

possible for planners to reduce the need for reserve generation and new transmission facilities. EIA recently

began collecting considerable information on distributed generation; there is no compelling reason to collect

more at this time.

Official Data on Reliability

Reliability Incidents, Outage Probabilities,

and Costs

Federal data on experienced lapses in grid reliability are

confined to Form EIA-417, “Emergency Incident and

Disturbance Report.” Form EIA-417 incident data have

been used primarily as a starting point for grid security

analyses. This form must be submitted to DOE’s Operations Center if one or more of the following apply:

• Uncontrolled loss of 300 megawatts or more of firm

system loads for more than 16 minutes from a single

incident

• Load shedding of 100 megawatts or more

• System-wide voltage reduction of 3 percent or more

• Public appeals to reduce the use of electricity

• Actual or suspected physical attacks that could affect

electric power system adequacy or reliability

• Actual or suspected cyber or communications

attacks

• Fuel supply emergencies

• Loss of electric service to more than 50,000 customers

for 1 hour or more

• Complete operational failure or shutdown of the

transmission and/or distribution system.

The types of data collected on Form EIA-417 include

information about the location, date, and time of the

incident, as well as the nature of the disturbance. Information about the cause of the incident (if known) and

the actions taken in response to the incident are also

requested. To illustrate, Table 5 provides a list of some

typical disturbances and unusual occurrences that were

reported on Form EIA-417 during 2002.

Of the 23 incidents reported, 7 were in California and 2

were in Florida. Oklahoma experienced the largest

blackout in terms of numbers of people affected.

Assuming complete reporting of qualifying events, it is

clear that major reliability failures are fairly common,

but they are spread around the country and involve a

small percentage of delivered power nationwide. At the

regional level of aggregation, the historical data suggest

that the frequency of failures is very low.

Outage Probabilities

John Doyle of the California Institute of Technology, and

others, have used NERC data to identify outage frequencies in North America from 1984 through 1997 (Figure

4).47 Their work shows that the frequency of large outages is significant. Similar displays can be constructed

from EIA data. The frequency of large outages follows a

20 Energy Information Administration / Electricity Transmission Data

Figure 4. North American Power System Outages,

1984-1997

Note: The circles represent individual outages in North America

between 1984 and 1997, plotted against the frequency of outages of

equal or greater size over that period.

Source: U.S.-Canada Power System Outage Task Force, Final

Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations (Washington, DC, April 2004),

p. 103.

47See B.A. Carreras, D.E. Newman, I. Dobson, and A.B. Poole, “Evidence for Self-Organized Criticality in a Time Series of Electric Power

System Blackouts,” submitted to the IEEE Transactions on Circuits and Systems Part 1 (May 2002), web site http://ffden-2.phys.uaf.edu/

papers/carrerasCAS02preprint.pdf.
power law, implying that the probability of outages

does not vanish as their size increases: very large outages cannot be ruled out as a practical matter. There are,

however, too few very large outages to demonstrate that

observed frequencies are accurate estimates of underlying probabilities at the regional level. For the same

reason, empirical estimates of changes in outage probabilities are of unknown accuracy.

Costs

There are no official data on the cost of reliability incidents. The Federal Government does not collect data on

customer expenditures for backup generators, power

quality protection, equipment damage, or insurance.

Consequently, it is not possible to identify trends in

actual losses or personal perceptions of the potential for

loss.

The Electric Power Research Institute (EPRI), the insurance industry, and other researchers have attempted to

compute annual costs resulting from power incidents.

Those efforts were not restricted to official data. Recent

estimates of the annual national cost of blackouts and

poor power quality range from about $20 billion to more

Energy Information Administration / Electricity Transmission Data 21

Table 5. Major Disturbances and Unusual Occurrences on the U.S. Electricity Grid, 2002

Date

Utility/Power Pool

and NERC Regiona Time Area Type of Disturbance

Loss of Load

(Megawatts)

Number of

Customers

Affected

Restoration

Time

January

1/30/2002 Oklahoma Gas & Electric (SPP) 6:00 Oklahoma Ice storm 500 1,881,134 2/7/2002 12:00

1/29/2002 Kansas City Power & Light (SPP) Evening Metropolitan Kansas City Area Ice storm 500-600 270,000 NA

1/30/2002 Missouri Public Service (SPP) 16:00 Missouri Ice storm 210 95,000 2/10/2002 21:00

February

2/27/2002 San Diego Gas & Electric (WSCC) 10:48 California Interruption of firm load 300 255,000 2/27/2002 11:35

March

3/9/2002 Consumers Energy Co. (ECAR) 12:00 Lower Peninsula of Michigan Severe weather 190 190,000 3/11/2002 12:00

April

4/8/2002 Arizona Public Service (WSCC) 15:00 Arizona Vandalism/insulators 0 0 4/9/2002

July

7/9/2002 Pacific Gas & Electric (WSCC) 12:27 California Interruption of

firm power

240 1 7/9/2002 19:54

7/19/2002 Pacific Gas & Electric (WSCC) 11:51 California Interruption of firm

power (unit tripped)

240 1 7/19/2002 16:30

7/20/2002 Consolidated Edison Co.

of New York (NPCC)

12:40 New York Fire 278 63,500 7/20/2002 20:12

August

8/2/2002 Central Illinois Light Co. (MAIN) 12:43 Illinois Interruption of

firm power

232 53,565 8/2/2002 18:36

8/9/2002 Lake Worth Utilities (SERC) 8:23 Florida Interruption of

firm power

51 25,000 8/9/2002 12:13

8/25/2002 Pacific Gas & Elec. (WSCC) 3:41 California Interruption of

firm power

120 1 8/25/2002 9:17

8/28/2002 Lake Worth Utilities (SERC) 14:09 Florida Severe weather 67.6 25,000 8/28/2002 15:38

October

10/3/2002 Entergy Corporation (SPP) 3:33 Coastal Areas of Southern

Louisiana

Hurricane Lily NA 242,910 10/4/2002 9:00

November

11/6/2002 Pacific Gas & Electric Co.

(WSCC)

22:00 Northern and Central

California

Winter storm 270 939,000 11/10/2002 12:00

11/17/2002 Long Island Power Authority

(NPPC)

15:48 Northport, NY, and Norwalk,

CT

Cable tripped 0 0 NA

11/17/2002 Northeast Utilities (NPCC) 6:00 Northwest and North Central

Connecticut

Ice storm NA 224,912 11/21/2002 8:00

December

12/3/2002 Entergy Corporation (SPP) 18:30 Arkansas Ice storm NA 43,000 12/5/2002 8:00

12/11/2002 Dominion-Virginia Power/North

Carolina Power (SERC)

13:09 Northern Virginia to

Fredericksburg and

Staunton to Harrisonburg

Winter storm 63 130,000 12/11/2002 13:45

12/14/2002 Pacific Gas & Electric (WSCC) 11:00 Northern and Central

California

Winter storm 180 1,500,000 12/18/2002 16:00

12/19/2002 Pacific Gas & Electric (WSCC) 6:00 Northern and Central

California

Winter storm 56 385,000 12/20/2002 17:00

12/25/2002 PPL Corporation (MAAC) 17:00 Eastern Pennsylvania Winter storm 250 106,000 12/26/2002 5:00

12/25/2002 Metropolitan Edison Co./

First Energy (MAAC)

10:00 Reading, York, Hanover,

and Hamburg, Pennsylvania

Winter storm NA 95,630 12/27/2002 8:30

a

NERC regions are defined in the Glossary.

NA = not available.

Source: Form EIA-417, “Electric Emergency Incident and Disturbance Report.”
than $400 billion.48 Researchers under contract to EPRI,

however, concluded after an exhaustive review of the

literature that:

There are few estimates of the aggregate cost of unreliable power to the U.S. economy. Documentation for

existing estimates is either absent or based on assumptions that need additional review.49

The lack of cost data makes it impossible to balance the

costs of reliability investments against cost savings.

Trends in Status of Grid Adequacy and

Security

Since outage and power quality data do not support estimates of near-term and regional reliability, it is natural

for government oversight groups to examine data on

recent and current conditions that affect grid adequacy

and security.

FERC Form 714, “Annual Electric Control and Planning

Area Report,” is the major official source of recent data

on reliability management. Control areas identify their

interconnections with adjacent control areas and their

scheduled and actual annual interchange (net power

flows into and out of the area) in the context of showing

the adequacy of their generation and transmission

resources. Each control area collects monthly generating

capability, net generation, and net interchange for the

reporting year. Significantly for reliability assessment,

the form also records how the control area met peak

hourly demand in each month.

FERC Form 714 is a double-entry account, so that net

transactions between adjacent control areas are reported

directly. Because control areas are associated wholly and

uniquely with NERC regions, estimates of regional

interchange could in principle be made by aggregating

individual reports.50 Unfortunately, discrepancies in

reporting are significant. While many of the receipts and

deliveries match exactly on both sides of the ledger,

there are some modest differences in delivery and

receiving area reports, possibly attributable to losses or

differences in metering. More unsettling are gaps in

reporting; e.g., one control area reports a delivery, but

the named recipient does not report a receipt. The information on power flows between control areas is not

sufficiently accurate, complete, or frequent to be useful

in assessing the grid’s ability to deliver power to control

areas that need it, when they need it.

Line outages, both scheduled and unscheduled, obviously limit how operators can affect power flows, but

they do not necessarily limit the grid’s ability to deliver

power. An increase in outages over time complicates the

task of delivering power and can point to underlying

problems, such as neglected maintenance, which could

eventually affect grid adequacy.

Data on transmission line availability are collected by

the 10 regional reliability councils and by many transmission-owning utilities. For example, ECAR (the East

Central Area Reliability Coordination Agreement) has

reported several interesting trends.51 Availability of the

345-kV system in ECAR in 2001 was the second lowest in

20 years, primarily because scheduled outage time

increased by 95 percent. The ECAR report notes that several of the longer outages in 2001 were attributable to

work being done to connect independent generators to

the grid.52 Similar availability data are not reported in a

standard form across NERC regions and are not readily

available for lines of 69 kV and above.

Sustained increases or decreases in line loadings on a

heavily loaded transmission path, corridor, or interface

can indicate a change in grid adequacy. The direction of

power flows is usually well known at peak times, and

the total corridor loading is equal to the sum of the loadings on a relatively small set of lines. These data are

maintained by NERC but are not publicly released.

A more direct measure of adequacy would be the number of hours that n-1, n-2, and higher level constraints are

actually binding within a control area and region. It

would be useful to know which lines are at a security

limit, when the constraint became effective, how much

power was curtailed, and the cost of redispatching the

system to meet demand. This information is generally

not available.

One publicly available indicator of grid adequacy is

NERC’s Transmission Loading Relief Database. The

information is unique to the Eastern Interconnection.53

This “Log” contains information about instances of

22 Energy Information Administration / Electricity Transmission Data

48J. Eto et al., Scoping Study on Trends in the Economic Value of Electricity Reliability to the U.S. Economy, LBNL-47911 (Berkeley, CA: Lawrence Berkeley National Laboratory, June 2001), p. 14.

49Ibid., p. x.

50“Dynamically scheduled load” is not included in net interchange. Dynamic resources are sources, usually generators, located outside a

region or control area whose output is dedicated to that control area. Because exchanges are explicitly balanced on FERC Form 714, no distortion should be introduced by the exclusion.

51East Central Area Reliability Coordination Agreement, 2001 Transmission Line Outages Summary Report, 02-TFP-46 (December 2002).

52Ibid., p. 5.

53FERC has endorsed the use of transmission loading relief orders to individual generators to keep line flows below area interchange

limits. Those orders are based on a transaction’s “priority” and not on its economic value. In addition, those generators who have a priority

cannot sell it to others who are willing to pay. A summary of recent curtailments appears in “Transmission Constraint Study,” presentation

of FERC staff to the Commission (December 19, 2001).
transmission inadequacy at flow gates (major pieces of

transmission equipment) and on major lines. In particular, it documents the requirement to implement NERC’s

TLR procedures on specified days to protect major parts

of the transmission system.54 Similar information is not

available for either the Western Interconnection or

ERCOT. The northeastern ISOs do not experience TLRs,

because they use prices rather than priorities to ration

transmission resources.

There are nine TLR levels. Level 0 is normal operation,

level 2 indicates that further increases would violate

security limits, and all higher levels require curtailments. The curtailments start with low-priority nonfirm

point-to-point service and continue up to curtailments

of firm point-to-point service. Figure 5 shows a plot of

TLR level 2 events by month of the year. Not surprisingly, TLRs increase significantly during the peak

demand months of July and August. NERC does not

report the volumes of power that are curtailed by TLRs.

NERC did, however, provide that information to FERC

staff writing the December 2001 curtailment study cited

in Chapter 4, Table 19.

Planning Data

The starting point for establishing prospective adequacy

is estimated future demand, especially peak demand.

FERC Form 714 requires planning areas to report their

actual hourly demand and to provide forecasts of summer and winter peak demand 10 years into the future.

The historical data could provide a benchmark for projections and serve as important data for modeling future

demand.

NERC submits Form EIA-411 on behalf of its 10 regional

councils. The data include 5-year projections of supply

and demand by NERC region. Supply means generation, but the form also identifies existing transmission

lines and proposed lines. The data can be used to

indicate whether projected generation within a

NERC region exceeds projected demand. The form

does not, however, contain the kinds of information

necessary to determine whether intra- and interregional

transmission are sufficient to deliver power where it is

demanded under peak or other definable conditions.

The coverage and relevance of the data collected on

Form EIA-411 to NERC’s short-term and long-term reliability assessments are unclear. The form is voluntary

and may or may not include entities that are not members of NERC. The instructions do not require that the

projects be consistent with those used in NERC’s reliability assessments or with the planning area projections

reported on FERC Form 714.

As referenced above under “Reliability Definitions and

Indicators,” NERC assesses power transfer capability

Energy Information Administration / Electricity Transmission Data 23

     













 





 

 



  





  











   







 

























































 















Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0

50

100

150

200

250

300

Number of Logs

2004

2003

2002

2001

2000

1999

1998

1997

















Figure 5. Level 2 or Higher Transmission Loading Relief Reports by Month, 1997-2004

Source: NERC.

54NERC’s web site,www.nerc.com, states “the NERC TLR procedure is an Eastern Interconnection-wide process that allows reliability

coordinators to mitigate potential or actual operating security limit violations while respecting transmission service reservations priorities.”
24 Energy Information Administration / Electricity Transmission Data

between interconnected regions and subregions and

publishes the “base” power transfers between regions

and the incremental transfer capabilities in each direction. Those data provide a measure of the additional

power that could be transferred from one region to a

neighboring region that experienced a sudden need for

support. High levels of incremental capability indicate

adequacy; low levels indicate the potential for shortages

to spread from one region to neighboring regions. Table

6 shows the transfer limits from MAIN to MAPP, SERC,

and TVA, under the conditions that NERC expected

during the summers of 2000 through 2003.

The capabilities are generally substantial, although the

values are for non-simultaneous conditions; i.e., these

limits could not all be approached at the same moment.

The limits also assume that all transmission facilities are

in service, all facilities are loaded within normal ratings,

and voltages are within normal limits.

The limits are subject to supply and demand conditions

that can cause base and incremental levels to change.

Time series and econometric projections would be

unlikely to anticipate the changes in base and incremental transfer capability shown in Table 6. The annual variations in base and incremental flows are sufficiently

large that they can be estimated only with the help of

models.

Analytical Tools

The planning data are one input to reliability assessments. In order to evaluate adequacy and security independently, government officials and their experts

require electrical models (power flow models) that accurately represent the relevant systems—whether control

area, NERC region, or interconnection.

FERC Form 715, “Annual Transmission Planning and

Evaluation Report,” is the major official source of the

information required to build power flow models used

to evaluate transmission adequacy and security.55

Transmitting utilities or their agents that operate networks at or above 100 kV submit the form to FERC annually. Normally, NERC Regional Councils submit Form

715 on behalf of their members. The required data

include:

• Power flow base cases for the respondent’s transmission system or, if the transmitting utility belongs to a

regional or subregional transmission planning or

reliability organization, power flow base cases for

that region or subregion

• System maps

• Descriptions of reliability criteria

• Evaluations of the transmission system’s current and

future performance.

The power flow cases are intended to be forward looking. FERC suggests that the cases include summer and

winter peak conditions for 1, 2, and 5 to 10 years into the

future. FERC also suggests that respondents include an

analysis of light and heavy transfers 1 year in the future.

Form EIA-411, “Coordinated Bulk Power Supply Program Report,” requires power flow data similar to those

provided on FERC Form 715 for newly planned transmission facilities.56 Specifically, Form EIA-411 requires

that respondents:

. . . submit a single annual peak load power flow case

that includes all prospective facilities to be energized in

the next two years. Alternatively, the respondent may

provide a copy of any annual peak load power flow case

that includes the new facility for the year it is to be energized. If more than one facility is to be energized in a

given year, it is acceptable to provide a single annual

peak load power flow case that includes all the new facilities added in that year.

Neither the FERC nor the EIA power flow data are publicly available because of the Federal Government’s concern with national security. The data are available for

official government purposes, including policy analysis.

Table 6. Base Transfers and Incremental Transfer Limits Among Selected NERC Reliability Regions and

Subregions, 2000-2003

(Megawatts)

Year

From MAIN to MAPP-US From MAIN to SERC TVA From MAIN to ECAR

Base Incremental

Incremental/

Base

(Percent) Base Incremental

Incremental/

Base

(Percent) Base Incremental

Incremental/

Base

(Percent)

2000 -235 1,900 -808.51 -388 3,300 -850.52 -61 4,000 -6,557.38

2001 -214 950 -443.93 -28 2,300 -8,214.29 55 4,000 7,272.73

2002 -214 950 -443.93 172 2,100 1,220.93 3 4,000 133,333,33

2003 392 1,000 255.10 -28 2,800 -10,000.00 905 3,200 353.59

Source: North American Electric Reliability Council, Summer Assessments 2000-2003.

55This description is taken from the form’s instructions, which can be obtained at web site www.ferc.gov/docs-filing/eforms/

form-715/instructions.asp.

56Form EIA-412 for municipal, State, Federal and generation and transmission cooperatives requires reporting of existing and new lines.

It does not require them to submit power flow cases.
Neither Form EIA-411 nor FERC Form 714 requires that

the planning data control areas and NERC regions submit data that are consistent with the assumed facilities,

grid configuration, or demands assumed in the FERC

Form 715 demonstration of reliability. It would not be a

violation of reporting instructions for regions to submit

Form EIA-411 and FERC Form 715 data that refer to significantly different visions of how reliability is to be

achieved.

The utility of the FERC Form 715 data is diminished by

the uneven quality of reporting. In particular, many of

the submitted cases violate line loading and voltage limits. Contrary to specific instructions, some respondents

do not identify generators with EIA-specified names,

making it expensive to merge EIA and FERC data. Contingency lists are unavailable, although the instructions

would seem to require them. And the information provided on service areas is not sufficient to locate demand

centers (load buses).

FERC Form 715 does not require power flow cases of the

respondent’s system as it currently exists; the data are

for a hypothetical system that the respondent expects to

exist in the future. This has two consequences: First, it is

not possible to use the FERC Form 715 data to compare

actual with calculated power flows as a means of validating the basic power flow model. Second, it is not possible to show how planned investments would provide

for additional transmission capability and security of the

existing system.

Because of the latitude respondents have for selecting

planning horizons, models of neighboring regions may

refer to different years. That makes it difficult, if not

impossible, to use the regional power flow models to

confirm NERC’s estimates of base and incremental

transfer capability. In fact, the cases do not specifically

identify new transmission facilities; that information is

available on Form EIA-411.

The electrical models that can be constructed directly

from these data include only the reporting area and

some of the lines connecting it to outside areas. Most of

the Form EIA-411 and FERC Form 715 data are at the

NERC region level. In assessing reliability and security,

imports from outside the reporting region can make the

difference between normal operation and blackout. One

way to bridge this information gap is with estimates of

how much power can be brought into a region that faces

temporary shortages. That is what NERC does with its

incremental transfer limits discussed above.

Another way to account for the reliability consequences

of imports and exports is to model the interconnections

in their entirety. FERC does not require that this be done.

For many years NERC has sponsored committees to

piece together their individual FERC Form 715 filings

into a description of the Eastern and Western Interconnections. This is an arduous, error-prone, and expensive

process. The resulting models, while useful, reflect the

problems of joining electrical descriptions that reflect

different assumptions, reference dates, aggregation conventions, and nomenclature. Currently, there are limited

tools for assessing reliability from a multi-region and

interconnection-wide perspective.

As demonstrated by the August 14, 2003, blackout, reliability problems cannot be managed or confined to a single utility, control area, or NERC region. Preliminary

analyses of the blackout’s progress have repeatedly

pointed to the fragmentary information available to system operators.57 As the grid becomes increasingly integrated, the need for interconnection-spanning electrical

models and supporting data will only grow.

Response to Markets

The growing importance of interregional power flows

and regional markets requires tighter control over the

grid than is customary in most of the country. High

quality electrical models of the regions and the relevant

interconnection are critical to achieving enough control

to allow commercial flows with minimal arbitrary

restrictions.

The incentives facing many market participants are to

push the costs of reliability, information, and system

control on to others. That way, they keep their own costs

low and can offer better terms than can “good citizens.”

Data on actual investments in the high-voltage

grid—how those investments were financed and who

paid for them—are necessary to quantify the extent of

the free-rider problem and to craft solutions. Investments in instrumentation, computation, communication, and other elements of system control are

particularly important. As discussed in Chapter 3, FERC

Form 1 reports aggregate investments and does not

make a clear distinction between distribution and

high-voltage transmission.

The advent of real-time pricing would make it possible

for customers to respond to prices and give system operators an additional tool for ensuring reliable service. As

discussed in Chapter 5, there is little official information

on how much load is currently metered to allow

real-time pricing, or the amount of power that is being

sold at real-time rates.58

Energy Information Administration / Electricity Transmission Data 25

57See, for example, E. Lipton, R. Perez-Pena, and M. Wald, “Overseers Missed Big Picture as Failures Led to Blackout,” New York Times

(September 13, 2003), pp. A1 and A10.

58Georgia Power and Gulf Power, among others, provide information about their real-time and time-of-use programs on the web site

www.metering.com.
Filling the Information Gaps

In the regulated, cost-of-service world, each utility could

reasonably be held accountable for reliable service

within its exclusive service area. Transmission was secondary to generation; it was cheap by comparison, and

utilities simply built lines as needed to serve their customers. With restructuring some utilities have divested

generation, and all are seeing power flowing across utility and regional boundaries in response to commercial

opportunities. That development, together with the

entry of independent generators supplying local and

distant markets, means that reliability is increasingly

dependent on building and managing transmission

capability.

Data collections that the Federal Government relies on

to monitor reliability have not kept pace with the ascendancy of transmission in a restructuring industry. The

government does not have the power flow models and

data necessary to verify the reliability of the existing system or to assess the efficacy of the industry’s reliability

plans as they relate to transmission within a region. The

industry’s reported plans are not necessarily those

imperfectly analyzed in the power flow analyses that

industry does submit to FERC. Data for monitoring

investments to improve control of the high-voltage grid

and indicators of reliability trends are not routinely

available to the government. Neither the industry nor

the government has data adequate to allow rigorous

cost-benefit analyses of transmission-related investments to enhance reliability.

Much improvement in the Federal Government’s capability to oversee reliability could be achieved without

new data collections. Instead, if FERC modified Form

715 and rigorously monitored the quality of responses,

government engineers could construct the power flow

models necessary to confirm current reliability and to

examine the efficacy of reliability plans. The FERC Form

715 power flow models frequently show electrical violations and reporting errors, and they do not necessarily

describe the existing grid. Government oversight would

be enhanced if the planning regimes described in FERC

Form 714 and Forms EIA-411 and EIA-860 were among

the cases evaluated in FERC Form 715. FERC and EIA

could accomplish that by first requiring the planning

data on FERC Form 714, Form EIA-411, and Form

EIA-860 to describe the same “plan.”59 FERC could then,

for example, require that the FERC Form 715 power

flows show how well the plan provides for “adequacy”

and “security” 1, 3, and 5 years into the future. Table 7

shows many of the specific changes that would be

required in existing FERC and EIA forms.

When reference power flow models are available for

regions, it will be appropriate for the Federal Government and NERC to construct interconnection-wide

26 Energy Information Administration / Electricity Transmission Data

Table 7. Reliability Data: Possible Changes to Existing Forms

Information Need Form Needed Changes Comment

1. High-quality power

flow models of

existing and

planned systems.

FERC 715 1. Identify load buses by MSA.a

2. Add selected power flow cases of existing system.

3. Model planning data for 1, 3, and 5 years in future.

4. Provide contingency lists.

5. Explain line and voltage violations.

The quality of reporting is uneven.

Submissions often do not use

EIA/EPA names and contain serious

electrical violations.

2. Data on the recent

adequacy, security

status of control

areas. Data to

verify power flow

models of existing

system.

FERC 714 1. Actual hourly demand, generation, inter-control-area

power flows experienced in control regions for selected

715 cases (2 above).

2. Experienced line and voltage violations.

3. Use EIA/EPA generator names and same line/bus

identifiers as on FERC Form 715.

3. A consistent set of

reference reliability

plans.

FERC 714,

EIA-411,

EIA-860

1. Require Forms EIA-411 and EIA-860 data to describe

the same plan.

2. Require FERC Form 714 (Part 111, Schedule 2) and

Form EIA-411 demand projections to be consistent.

These plans should be the basis for

the power flow analyses 1, 3, and 5

years into the future.

4. Monitor potential

demand response.

EIA-861 Add a schedule showing annual total megawatthours

metered hourly (or higher frequency) and megawatthours

billed by time of consumption.

To quantify extent of price responsive

demand (see Chapter 5).

5. Investment in

metering and

control of the

high-voltage grid .

FERC 1,

EIA-412

1. Adopt NIPA definition of investment.

2. Report investment in metering, communication, software,

and control of the high-voltage grid.

See Chapter 3.

a

MSA stands for Metropolitan Statistical Area. An MSA is a geographic entity defined by the U.S. Office of Management and Budget. Qualification

as an MSA requires the presence of a city with 50,000 or more inhabitants, or the presence of an Urbanized Area (UA) and a total population of at

least 100,000 (75,000 in New England).

59Form EIA-860 does require that identified planned power plants and generators be taken from “planning data.” Planning data are not

defined on the form.
models. The government’s ability to monitor trends in

reliability could be substantially improved if NERC and

FERC built a time series database on security limits

experienced on high-voltage lines and flowgates;

curtailments; denied service; and power flows across

the high-voltage grid. That would require a formal

agreement between FERC and NERC. Data on the costs

of blackouts and substandard power quality, including

what people spend to protect themselves, would also be

useful. Given the other needs, however, those data are of

relatively low immediate priority.

Energy Information Administration / Electricity Transmission Data 27

3. Financial Performance and Investment

Introduction

Within two weeks of the blackout on August 14, 2003,

the Wall Street Journal reported:

The nation’s electric power industry . . . is preparing to

launch a public-education campaign to help it raise

$100 billion from investors, governments, and consumers to upgrade the nation’s power grid.60

The estimate seemed plausible to the press, given the

Federal Government’s frequently expressed concerns

about investment in the Nation’s power grid; but within

3 months, Public Utilities Fortnightly published an article

that stated:

We don’t know what caused the . . . blackout but somehow we know that our transmission system needs $50

billion to $100 billion in investment and upgrades. And

utilities need higher returns . . . . The reality is that we

aren’t short $50 billion or $100 billion .... [T]he study

said to support that conclusion doesn’t do the job.61

For the foreseeable future, Federal and State policymakers will remain at the center of these controversies.

Their policy decisions will greatly affect the level of

investment, where investment occurs, the profitability

of the transmission business, who pays for transmission

service, and how much they pay. To make informed

decisions, policymakers require relevant and accurate

data to guide their judgments.

FERC is charged with ensuring “just and reasonable”

prices for power in interstate commerce. State regulators

continue to be deeply involved in transmission regulation in most States. They effectively regulate transmission costs and prices for “internal transactions” and also

control siting and eminent domain.

FERC has long collected data on capital and operating

costs from IOUs. FERC uses the information to ensure

that tariffs for delivered electricity sales bear a reasonable relation to costs. EIA complements the FERC collections with less detailed reports from other generation

and transmission owners to produce industry-wide

totals. Both agencies focus on generation and distribution data, because the costs of transmission are a small

portion of total costs. In 2000, for example, the transmission operating costs of major public utilities averaged

only 4 percent of their total operating costs.62 Transmission plant was 11 percent of total electric plant in service.63 In a cost-of-service world where all costs are

bundled together to form a single price for delivered

electricity, the specific costs of transmission are unimportant.64

Restructuring of the electricity industry has broadened

FERC’s perspective beyond cost recovery to the economics of transmission. FERC Order 2000, establishing

RTOs, notes that “effective and efficient RTOs . . . [are]

dependent in large measure on the feasibility and vitality of the standalone transmission business.”65

The difficulty in obtaining financial data that show

“vitality” is that transmission is rarely a standalone business. Almost all IOUs derive most of their total revenues

from supplying bundled power (energy, transmission,

and services) to native customers at State-regulated

prices. Separate transmission prices and revenues for

internal customers do not exist. Merchant transmission

companies only sell transmission, but they are minuscule. Cooperatives and public power entities are not in

the business of selling transmission capacity. The only

“market-like” transmission prices are those that customers pay for wheeling power across a system. Wheeling

Energy Information Administration / Electricity Transmission Data 29

60J.J. Failka, “Power Industry Sets Campaign to Upgrade Grid,” Wall Street Journal (August 25, 2003), p. A3.

61S. Huntoon and A. Metzner, “The Myth of the Transmission Deficit,” Public Utilities Fortnightly (November 1, 2003), p. 28.

62Energy Information Administration, Electric Power Annual 2001, DOE/EIA-0348(2001) (Washington, DC, March 2003), Table 8.3, “Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (With Generation Facilities), 1990 through 2001,” p. 51, web site

http://tonto.eia.doe.gov/FTPROOT/electricity/034801.pdf.

63See Energy Information Administration, Financial Statistics of Major U.S. Publicly Owned Electric Utilities 2000, DOE/EIA-0437(00)

(Washington, DC, November 2001), Table 11, “Electric Utility Plant for Major U.S. Publicly Owned Generator Electric Utilities at End of

Period, 1996-2000,” p. 20, web site www.eia.doe.gov/cneaf/electricity/public/t11p01p1.html.

64The transmission grid’s relatively small costs do not mean that its efficient operation and development are unimportant. Efficiency

reduces costs in the short run and ensures that the grid is not a drag on economic growth and competition. Efficient grid operation generally

means that the grid’s services are priced at marginal cost. Efficient development means that all potential investments are considered and the

investments made are those whose net benefits, adjusted for risk and timing, are greatest. The need to consider all relevant investments is

easy to overlook. Line congestion, outages, and other transmission problems may best be solved by investments in distributed generation,

demand-side management, or other alternatives to transmission facilities.

65Federal Energy Regulatory Commission, Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (June 6, 2000); FERC

Stats. & Regs. at 31, 170.
revenues, however, are a very small portion of total

revenues.

Measures of Financial Performance

and Investment

There is considerable agreement about how financial

performance—unlike reliability—should be measured,

and how financial data should be interpreted. There are,

nevertheless, long-standing debates about how to obtain

better agreement between accounting and economic values and how to value uncertain prospects and illiquid

assets. FERC requires that utilities it regulates use the

Uniform System of Accounts. Those accounts are more

detailed and require far more disclosure than is usual for

publicly traded companies.

FERC collects financial and operating data annually

from major privately owned electric utilities on FERC

Form 1, “Annual Report of Major Electric Utilities,

Licensees and Others.”66 FERC requires utilities under

its jurisdiction to submit the following schedules for the

calendar year:

• Comparative Balance Sheet

• Statement of Income

• Retained Earnings

• Statement of Cash Flows

• Notes to Financial Statements.

The data are entered on the form pursuant to the Commission’s Uniform System of Accounts Prescribed for

Public Utilities and Licensees Subject to the Provisions

of the Federal Power Act.

The transmission revenues reported on FERC Form 1 are

those for wheeling power for others. Form 1 specifically

identifies 15 subcategories of transmission operation

and maintenance costs (page 321), as well as the book

values (acquisition costs) for 9 subcategories of transmission plant and equipment (page 206). The form also

identifies calendar year additions to transmission plant

and equipment. The revenues from transmission of electricity for others (Account 456) are segmented into

energy charges, demand charges, and other charges.

FERC has proposed to require explicit reporting of purchases and sales of ancillary services.67 Debt, stockholder equity, taxes, and miscellaneous expenditures

are listed and described in detail. In addition to providing FERC with information to assist in reviewing company tariffs and investments, FERC Form 1 is used by

financial analysts to assess private utilities’ short-term

solvency, financial risk, long-term viability, and returns

to investment and investors.

EIA collects data on an abbreviated version of FERC

Form 1—Form EIA-412—on an annual basis from publicly owned utilities (municipalities, political subdivisions, States, and Federal entities). EIA requires the

following schedules for the respondent’s fiscal year:

• Balance Sheet

• Income Statement

• Electric Plant

30 Energy Information Administration / Electricity Transmission Data

Ratio Analysis

Financial analysts often examine operating efficiency

ratios and operating profitability ratios to better

understand how firms generate profits. In a typical

application, a financial analyst would decompose

return on equity (ROE, equal to net income divided

by equity) into components to highlight differences

among firms. A popular decomposition is the DuPont

identity, which expresses ROE as the product of profit

margin, total asset turnover, and financial leverage:

Return on Equity =

Net Profit

Margin

 Total A



 



 ×

sset

Turnover

Financial Leverage

Multip





 



 × lier

Net Income

Sales

Sales

Total Assets





 





= 



 



 ×





 



 ×





 



 Total Assets

Equity .

An example of two hypothetical firms, both of which

earn 12 percent per year on equity, illustrates how

these decompositions assist in financial analysis:

Firm

Net Profit

Margin

Asset

Turnover

Financial

Leverage

Multiplier ROE

A 8% 2.0 0.75 12%

B 3% 1.0 4.00 12%

While both firms have the same ROE (12.0 percent),

the underlying means of generating ROE are very different. Firm A has high net profit margins, high turnover, and low financial leverage. Firm B has low net

profit margins and low operating efficiency but has

used financial leverage to increase its return. Richard

Brealey and Stewart Myers discuss the limits of

DuPont ratios in Financing and Risk Management (New

York, NY: McGraw-Hill, 2003), p. 366.

66FERC has proposed collection of quarterly financial data on a new Form No. 6-Q. See Federal Energy Regulatory Commission, “Quarterly Financial Reporting and Revisions to the Annual Reports,” 18 CFR Parts 141, 260, 357, and 375 (June 26, 2003).

67Federal Energy Regulatory Commission, “Quarterly Financial Reporting and Revisions to the Annual Reports,” 18 CFR Parts 141, 260,

357, and 375 (June 26, 2003), Appendix B.
• Taxes, Tax Equivalents, Contributions, and Services

During the Year

• Sales of Electricity for Resale

• Electric Operation and Maintenance Expenses.

Like FERC, EIA collects data on wheeling revenues. EIA

encourages, but does not require, respondents to use the

Uniform System of Accounts. Analysts use the data to

compare the operations of publicly owned utilities and

IOUs and to evaluate potential public exposure to their

debt. EIA uses the data to complete its statistical description of the industry.

No system of accounts, no matter how conscientiously

applied, captures all economic values perfectly. Transmission equipment, for example, is very long-lived,

making book values poor measures of either replacement or market value. Most utility land holdings,

likewise, were acquired long ago, and valuable rightsof-way assets were originally obtained under the

implicit threat of eminent domain. Market values for

many such assets are unavailable.

Impact of Restructuring

on Relevant Financial Data

FERC Order 888 required all public utilities that own or

control interstate transmission capacity to functionally

unbundle wholesale power services. Functional unbundling requires the public utility to do the following:

• Take transmission services under the same tariff as

others

• Post separate rates for wholesale generation, transmission, and ancillary services

• Rely on the same information system that its customers use.

FERC considered, but did not require, divestiture of

transmission from generation and institutional changes

to achieve functional unbundling. Nor did it require

public utilities to spin off transmission into standalone

business units.

With the growth of independent power suppliers, the

transmission business has become something of a mongrel. The utility that owns transmission capacity earns

revenues by charging others posted rates for wholesale

transmission and related services; it charges itself for its

own wholesale sales at the same rates. The utility neither

posts transmission rates for bundled retail sales nor

charges itself for transmission. Instead, the charges for

transmission are bundled with the price of delivered

power. Because FERC has not required “financial

unbundling” by line of business, it is not possible to

identify total transmission revenue or to know whether

the utility is charging nondiscriminatory rates for transmission service to retail customers.

Because reasonable transmission rates for others are

defined in part on the basis of costs, sharp distinctions

between transmission costs and the costs of distribution

and generation are important under restructuring.

FERC Form 1 allows respondents to determine their

own boundaries, making meaningful comparisons

across transmission providers difficult if not impossible.

An implicit assumption behind financial accounts is that

each company’s revenues and costs capture its major

economic benefits and costs. Before system interconnections and large power flows across systems became

important, integrated utility costs and benefits were

essentially the same as total costs and benefits; i.e., they

were internal to the utility. The same identification is

dubious in a restructuring electricity industry.

An economically important external cost occurs when

one system’s operations load lines in another system (or

systems) to the extent that an affected system cannot use

its lines as it otherwise would. Lines loaded to their security limits are congested. In a connected AC system, electricity flows everywhere in response to relative line

resistance (impedance) and the locations and amounts

of generation and consumption. How an operator

decides to dispatch generators, secure imports, or otherwise meet (or refuse to meet) demand can cause lines to

be congested far outside his or her system’s boundaries.

Faced with line congestion, operators can only meet

their customers’ increased demands by operating more

costly, but better situated, generators. Those additional

costs show up in the books of the affected system; costs

are artificially lower in the books of the system causing

the congestion.68

Congestion costs within individual systems are being

measured and valued (inconsistently) in a few parts of

the country. Chapter 4 contains a discussion of congestion costs and revenues. Those costs are not identified on

FERC Form 1.

FERC’s Order 2000 would bring together many transmission providers into a few RTOs. In a regional setting,

individual companies cannot be held solely responsible

for the costs borne by customers. A particular company

may experience abnormally high costs because it has

made expenditures that reduce overall regional costs;

another may have artificially low costs because it

exploits “beggar thy neighbor” opportunities.69 In a

restructured industry the costs of an RTO as a

Energy Information Administration / Electricity Transmission Data 31

68Operating decisions that relieve congestion and lower costs in other areas are not compensated either.

69One role of RTOs is to internalize significant external costs and manage them on an equal footing with each system’s cash costs.
whole—not just its individual companies, which report

on FERC Form 1— would be relevant to costs, tariffs,

and investments.

Restructuring has also motivated public policy concern

about the level and kinds of investment being made in

the grid. FERC Form 1 collects data on transmission

plant and equipment and additions to plant and equipment. Unlike the National Income and Product

Accounts, the “additions” data are not restricted to

acquisitions of new equipment. “Plant and equipment”

refers to the purchase price of any qualifying good,

including land, regardless of its age. When a utility sells

old equipment at above net book value to another

reporter, the data show net additions, despite the fact

that nothing has changed on the ground. Generators

have been sold for much more than net book value in the

recent past. Net additions (after subtracting land acquisitions) may or may not be a good proxy for the economic concept of investment.

As mentioned in Chapter 2, NERC has stated that power

flows today are more volatile and more likely to change

course than they were before restructuring. In the present environment, investment in system metering, communication, computation, and control is critical to

improving reliability. Capital investment in these areas

is not identified on FERC Form 1.

Restructuring has also brought about transmission

investments from new entities, such as merchant transmission companies. As discussed in Chapter 4, new

independent generators are making significant investments in the grid as a condition of connecting to it.

Because FERC does not require merchant companies

and independent generators to submit detailed financial

reports, those investments may not be recorded in official data.

In a fully restructured environment, financial data for

evaluating the economics of transmission would

include:

• Standalone financial accounts for the transmission

business

• Estimates of external costs and benefits, especially

the value of congestion

• Integration of individual transmission provider

accounts to the appropriate RTO

• Complete investment totals that identify investments undertaken for grid control.

Official Transmission Financial Data

Standalone Accounts

Except for those few utilities that are strictly dedicated to

transmission, it is not possible using official data to construct standalone financial statements for transmission.

Both Form EIA-412 and FERC Form 1 identify transmission sold (purchased) from others. FERC has proposed

that utilities report the grid’s sales (purchases) of ancillary services. Neither form reports transmission nor

related services provided to the utility’s own generators.

As a consequence, it is not possible to calculate transmission’s returns on either investment or equity. Ratio analysis of the kind sketched above cannot be performed.

Official data do, however, indicate how restructuring

has affected revenues from transmission sales to others.

Transmission Revenues

Transmission for others, called wheeling, has grown

since the start of restructuring (1996) in some regions

and declined in others. Nationwide volumes and revenues more than doubled from 1996 to 2001. Tables 8 and

9 show gross wheeling volumes and revenues for utilities located in the North Central States (ECAR), Midwest

(MAPP), and West (WECC) NERC regions and for the

total United States.

Figure 6 shows the average revenue per MWh from

wheeling for the three regions, which varies from a low

of slightly more than $1 per MWh in 1994 in the MAPP

region to highs of slightly less than $6 per MWh in 1998

and 2000 in the ECAR region. Over time, the range in

price difference among the three regions has varied

between roughly $0.50 per MWh and $4.50 per MWh.

Revenues from Grid-Supplied Ancillary

Services

FERC does not currently collect information on the

prices, volumes, or revenues earned from ancillary services provided in the transmission sector, although it

has proposed collecting information on ancillary service

revenues. Because the grid is often the major, if not sole,

source of ancillary services, however, it would also be

useful to collect price and corresponding volumetric

information, which could be used to determine whether

grid-supplied services are priced at marginal cost. The

OASIS sites of transmission providers contain some

ancillary service prices, but they are incomplete, do not

include volumes, and are not maintained as a time series

(see Chapter 4). The ISOs report some scattered, incomplete information on their web sites.

Operations and Maintenance Costs

Official data also include utility operating costs. Table 10

shows the total operations and maintenance costs for

utilities in the WECC, MAPP, and ECAR regions. In

2002, wheeling revenues were about 75 percent of operations and maintenance costs in the ECAR region, almost

60 percent in WECC, and about 25 percent in MAPP.

Book Values of Plant and Equipment

FERC maintains voluminous records on the book values

of plant and equipment and their depreciation. FERC’s

32 Energy Information Administration / Electricity Transmission Data
concentration on the book value of transmission assets

reflects its concern with the recovery of prudent costs,

including a reasonable return on capital. These historical

costs, and their associated debt, will continue to be

important to FERC’s determination of capital recovery

for wholesale transmission. The difference under

restructuring is that the precise boundaries between

transmission, generation, and distribution matter.

External Costs and Benefits

The Uniform System of Accounts underlying FERC

Form 1 does not attempt to identify or value the benefits

and costs that responding utilities impose on others.

Congestion and reliability are leading examples of these

costs and benefits, respectively. Congestion internal to

the northeastern ISOs is being valued and paid for by

market participants. Chapter 4 explains how congestion

is valued and presents recent estimates of congestion

costs.

Regional Accounts

FERC does collect data from RTOs or ISOs; however,

utilities are not required to provide separate accounts

for their assets in different RTOs or ISOs. This is not a

problem currently, because most of the U.S. electricity

industry operates outside the RTO/ISO structure; but at

Energy Information Administration / Electricity Transmission Data 33

Table 8. Gross Volume of Wheeling in Three NERC Regions, 1993-2002

(Billion Kilowatthours)

Year ECAR MAPP WECC United States

1993 28.4 14.1 74.6 268.6

1994 26.2 16.5 65.2 252.6

1995 29.7 15.5 64.4 264.2

1996 55.2 15.2 69.7 303.8

1997 61.7 17.2 67.4 326.4

1998 67.6 18.7 73.7 373.3

1999 67.9 22.2 76.9 370.1

2000 85.4 18.8 87.1 490.5

2001 157.3 18.8 112.1 671.8

2002 159.4 13.8 105.5 705.8

Source: Energy Information Administration, based on the Resource Data International (now Platts) PowerDat compilation of data from FERC

Form 1.

Table 9. Gross Revenue from Wheeling in Three NERC Regions, 1993-2002

(Million 2002 Dollars)

Year ECAR MAPP WECC United States

1993 109.29 22.14 224.50 1,362.01

1994 112.27 21.99 212.91 1,365.09

1995 121.15 30.03 198.17 1,373.15

1996 189.08 38.31 231.88 1,541.67

1997 235.31 61.04 240.63 1,821.70

1998 370.58 57.21 232.01 2,181.30

1999 335.68 44.20 294.18 2,417.00

2000 484.71 51.17 352.33 2,828.12

2001 546.53 56.15 469.15 3,400.21

2002 632.31 56.13 470.24 3,968.41

Source: Energy Information Administration, based on the Resource Data International (now Platts) PowerDat compilation of data from FERC

Form 1.

,

,

, , , , ,

, , ,

'

'

'

'

'

'

'

'

'

'

& &

&

&

&

&

&

&

&

&

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

0

1

2

3

4

5

6 2002 Dollars per Megawatthour

WECC

ECAR

MAPP

Figure 6. Gross Revenue from Wheeling in Three

NERC Regions, 1993-2002

Source: Energy Information Administration, based on the Resource

Data International (now Platts) PowerDat compilation of data from

FERC Form 1.
such time as those organizations come to operate large

portions of the grid, consolidated regional accounts may

become necessary for evaluating regional transmission

costs and investments.

Utility Investment and Capital Stock

Much has been made of the slow growth in the highvoltage grid relative to the growth in electricity generation. For example, NERC publishes an annual compilation of lines 230 kilovolts and above. As shown in Table

11, the number of high-voltage transmission circuit

miles has grown at a compound rate of about 0.6 percent

per year since 1990, while generation has grown at a

compound rate of nearly 2 percent per year from 1990

through 2002.

Annual “investment” data show little change in response to either generation or increased wholesale trade

(see Table 20 in Chapter 4). FERC Form 1 and Form

EIA-412 record capital additions for publicly owned

utilities and IOUs. RUS Forms 7 and 12 report investment data for cooperatives. Table 12 shows annual capital additions to transmission plant in service from 1988

through 2002. Some of the additions represent purchases of existing facilities (and land) and therefore are

not investments in the sense of the National Income

Accounts. As noted earlier, publicly owned utilities

report to EIA on a fiscal year basis and IOUs report on a

calendar year basis. The annual totals are thus a mixture

of fiscal and calendar year expenditures. Moreover, the

boundaries between transmission and distribution vary

among reporters.

Independent Power Producers, Merchant

Transmission, and RTO/ISO Investments

Independent power producers do not report their

costs for connecting to the grid. To some extent, the costs

they incur for grid reinforcement may be reported on

FERC Form 1, but if so they are not identifiable. Merchant transmission companies do not report capital

investment to either FERC or EIA. RTOs and ISOs are

considered utilities by FERC and are required to report.

Filling the Information Gaps

FERC collects capital and operating cost data from IOUs

as part of its responsibility to ensure just and reasonable

electricity prices. EIA complements the FERC collections

with less detailed reports from the other generation and

transmission owners to produce industry-wide totals.

FERC’s Commissioners are concerned with the economics of transmission as a standalone enterprise because of

their obligation to ensure just and reasonable prices in a

restructuring environment. But FERC’s financial

accounts are more appropriate to the circumstances of

34 Energy Information Administration / Electricity Transmission Data

Table 10. Total Operations and Maintenance Costs for Transmission in Three NERC Regions, 1993-2002

(Million 2002 Dollars)

Year ECAR MAPP WECC United States

1993 414.27 182.66 1,003.33 2,623

1994 423.20 205.65 1,021.57 2,631

1995 412.54 213.68 1,016.04 2,744

1996 420.06 223.42 1,044.68 2,598

1997 400.53 249.22 1,091.33 3,363

1998 442.11 340.38 1,264.55 3,789

1999 448.54 269.00 1,293.42 4,018

2000 540.14 274.36 1,166.54 4,401

2001 691.16 203.12 950.95 4,089

2002 810.76 220.70 827.02 5,238

Source: Energy Information Administration, based on the Resource Data International (now Platts) PowerDat compilation of data from Form

EIA-412, FERC Form 1, and RUS Forms 7 and 12.

Table 11. Comparison of Changes in High-Voltage

Transmission Infrastructure and

Electricity Generation, 1990-2002

Year

Transmission Lines

(Circuit Miles)a

Generation

(Billion Kilowatthours)

1993 147,271 3,038

1994 148,059 3,074

1995 149,020 3,084

1996 150,953 3,197

1994 150,826 3,248

1995 150,111 3,353

1996 152,098 3,444

1997 153,533 3,492

1998 154,679 3,620

1999 155,669 3,694

2000 156,435 3,802

2001 157,314 3,736

2002 158,605 3,838

a

Includes AC and DC lines 230 kilovolts and above.

Sources: Transmission Lines: North American Electric Reliability

Council, Electricity Supply and Demand Database software (2003),

available at web site www.nerc.com. Generation: Energy Information

Administration, Annual Energy Review 2002, DOE/EIA-0384(2002)

(Washington, DC, October 2003).
integrated regulated utilities selling bundled electricity

in a cost of service environment.

Apart from a few “transmission only” entities, FERC

Form 1 says little about the economics of transmission.

Official data do not capture transmission’s financial performance, in large part because most transmission revenue is bundled with revenue from retail sales and is not

separately identifiable.

If transmission were fully unbundled, its revenues

would be unambiguous. Absent that, FERC could

require line-of-business reporting—a fundamental

change that would be tantamount to introducing a new

data collection form. How useful or valid the resulting

estimates would be is a serious question.

Far less dramatic changes to FERC Form 1, Form EIA412, and Form EIA-860 would make the data more useful for cost and investment (but not financial) analysis.

Precise definitions of transmission would be a logical

place to start. The available data describing transmission

operation costs, capital stock, and investment are not

comparable across reporters, because neither FERC

Form 1 nor Form EIA-412 imposes a common definition

separating transmission from distribution.

The “investment” series derived from official data are

flawed in at least three other ways. First, additions to

transmission plant and equipment reflect not only new

investment but also purchases of existing assets from

others, land purchases, and other expenditures that,

while relevant for some purposes, are not “investment”

in the sense of the National Income and Product

Accounts.70 The EIA forms that are modeled after FERC

Form 1 share those attributes. Second, EIA, unlike FERC,

collects financial data on a fiscal year basis rather than a

calendar year basis. Consequently, EIA and FERC

investment and other financial data cannot be added to

arrive at a valid national total. Third, official data do not

appear to capture investment in the grid by new market

participants: merchant transmission companies and

independent power producers.

Official financial statistics are not informative about

transmission revenues and costs, such as ancillary service and redispatch costs, that restructuring makes visible in prices. As Regional Transmission Organizations

become more prominent, it will be increasingly important to allocate transmission costs to particular organizations. The kinds of changes to existing forms that would

be required are shown in Table 13.

Energy Information Administration / Electricity Transmission Data 35

Table 12. Annual Capital Additions to Transmission Plant in Service, 1988-2002

(Million Dollars)

Year

Nominal Dollars

Public Utilities Investor-Owned Utilities Cooperatives Total Total 2002 Dollars

1988 910.48 2,027.85 2,938.33 4,053.31

1989 1,126.49 2,179.64 3,306.13 4,393.48

1990 522.33 2,622.63 3,144.96 4,022.00

1991 811.06 2,174.25 2,985.31 3,684.37

1992 789.26 2,498.62 3.38 3,291.26 3,965.35

1993 683.33 2,378.64 121.63 3,183.60 3,745.63

1994 614.52 2,529.35 191.84 3,335.72 3,844.74

1995 964.96 2,430.74 191.03 3,586.73 4,045.69

1996 1,300.00 2,312.90 206.90 3,819.81 4,226.86

1997 851.96 1,957.70 149.74 2,959.40 3,212.23

1998 640.78 2,173.06 255.16 3,069.00 3,290.61

1999 708.58 2,308.66 156.19 3,173.43 3,354.35

2000 929.74 2,612.89 192.55 3,735.18 3,866.69

2001 836.67 4,217.03 246.27 5,299.97 5,359.81

2002 1,124.13 3,302.30 220.33 4,646.75 4,646.75

Source: Energy Information Administration, based on the Resource Data International (now Platts) PowerDat compilation of data from Form

EIA-412, FERC Form 1, and RUS Forms 7 and 12.
36 Energy Information Administration / Electricity Transmission Data

Table 13. Financial and Investment Data: Possible Changes to Existing Forms

Information Need Form Needed Changes Comment

1. Consistent

separation of

transmission

from distribution

accounts.

FERC 1,

EIA-412

Explicitly define transmission in the same way for all utilities

and use that definition in assigning costs, revenues, and

net capital.

Current data are an “apples and

oranges” mix.

2. Utility investment in

the high-voltage

grid.

FERC 1,

EIA-412

1. Adopt NIPA definition of investment.

2. Report line and associated equipment investment

by voltage level.

3. Report investment in metering, communication, software,

and control of the high-voltage grid.

Current “additions to plant and

equipment” data have very limited use

for economic and reliability analysis,

although they are important to capital

cost recovery.

3. IPP investment. EIA-860 Collect direct connection and grid reinforcement costs from

IPPs on EIA 860.

Some of these investments may not

be picked up on FERC Form 1. See

Chapter 4.

4. Merchant

transmission

investment.

EIA-412 Add to the list of respondents and require them to report

transmission investments, as defined above, and to fill out

Schedules 10 and 11.

Merchant investment and line data are

not currently collected.

5. Ancillary service

revenues.

FERC 1,

EIA-412

Require reporting as proposed by FERC.

6. Re-dispatch costs. FERC 1,

EIA-412

Require reporting. Only applicable to utilities owning

generators. Not necessary for ISOs.

7. Regional costs. FERC 1,

EIA-412

Require reporters to disaggregate cost, revenue, net capital

stock, and investment by appropriate region.

This would allow regional cost

comparisons.

8. Consistent

aggregation.

EIA-412 Adopt FERC definitions (see above) and require reporting

by calendar year.

EIA currently allows reporting by fiscal

year.
4. Transmission and Wholesale Power Markets

Introduction

For almost a decade, FERC has been attempting to create

competitive wholesale electricity markets by opening

the Nation’s electricity transmission grid to competing

generators, by promoting regional transmission markets, and by encouraging investment in transmission

capability.71 If its policy initiatives succeed, FERC would

transform large areas of the country into “common markets” for electricity commerce. The transmission grid

would become a network of superhighways for markets,

seamlessly moving power across the country to reduce

costs and improve reliability.

Despite FERC’s efforts, much of the United States

remains more like a collection of loosely connected toll

roads than a network of superhighways. Unlike the

interstate highway system, the high-voltage grid has

hundreds of owners, including governments and IOUs,

each manning a tollbooth. Each transmission owner

built a section of the grid to serve its retail customers

(native load), and interconnections between systems

were primarily for improving reliability and sharing

occasional surpluses. The grid was not designed or built

with the idea of supporting large regional markets.

Electricity markets are dependent on the grid to connect

buyers and sellers and to consummate trade agreements. When lines serving Chicago, for example, are

congested, outside suppliers are unable to deliver additional volumes, and shortfalls in meeting demand must

be met by higher cost local generation. Generators

located within such load pockets are well positioned to

charge prices significantly above their relatively high

(marginal) costs. Congestion effectively fragments markets to the detriment of competition.

Even when transmission resources are sufficient to

move power to higher price areas, buyers and sellers

may be unable to execute mutually beneficial trades,

because each region has its own rules, operating practices, and charges for importing and exporting power.72

The administrative difficulties and costs of coordinating

power flows across system boundaries can be serious

obstacles to trade. Resolution of these “seams” issues is a

prerequisite for further market integration.

This chapter considers data useful for gauging the grid’s

support of larger, more competitive markets. Data are

needed to answer questions such as: Are generators able

to access and connect to the grid? Are the costs and quality of transmission service nondiscriminatory and reasonable? Are bottlenecks, load pockets, and large

congestion costs prevalent? Are the costs of moving

power across system-control boundaries large and

growing? Is power readily flowing from low-price to

high-price areas? Are there persistent and large differences in regional wholesale prices? Are FERC’s policy

initiatives succeeding?

The available data are only evidence that the grid is (or is

not) being used in ways that are more (or less) consistent

with expanding markets and competition. They are not

absolute measures of the size of markets and the trade

possibilities the grid defines.

Measuring the Grid’s Impact on

Wholesale Markets

The fundamental measures of the grid’s impact on markets are the potential size of the markets (defined by the

grid’s capabilities) and the volumes of economic trade

they could support. Economic trade is undertaken in

response to price differences: the greater the difference

in price, the greater is the volume tending to flow to the

higher priced market. Market organization, regulation,

and transaction costs can cause actual market size and

trade volumes to be substantially less than their

potential.

Electrical models of the grid are generally necessary to

determine which suppliers are physically able to serve

markets.73 Unlike highway transportation, geographic

separation neither measures transmission “distance”

between generators and markets nor explains its cost.

Energy Information Administration / Electricity Transmission Data 37

71See Federal Energy Regulatory Commission, Promoting Wholesale Competition through Open Access Nondiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, Final Rule, 18 CFR Parts 35 and

385 (April 24, 1996); Regional Transmission Organizations, Order No. 2000, Final Rule, 18 CFR Part 35 (January 6, 2000); Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design, Notice of Proposed Rulemaking, 18 CFR Part 35,

Docket No. RM01-12-000 (Washington, DC, July 31, 2002); and Proposed Pricing Policy for Efficient Operation and Expansion of Transmission

Grid, Notice of Proposed Rulemaking, 18 CFR Part 35, Docket No. PL03-1-000 (Washington, DC, January 15, 2003).

72“Region” here refers to the full range of electrical control hierarchies, including Control Areas, ISOs, RTOs, and NERC regions.

73FERC has used confidential company sales information in merger cases to establish historical market boundaries. That information

neither identifies all potential suppliers nor shows the effect of changes in grid configuration and use patterns on the list of potential competitors. Chapter 2 contains a brief discussion of electrical models.
Electrical models are also necessary to determine how

much power could be moved from suppliers to markets.

Unlike a highway, a transmission line may be congested

(unable to carry more energy) when carrying only a fraction of its rated capacity. The Federal Government does

not maintain reference electrical models of the grid and,

therefore, has limited means to establish potential market size. Practicable measures focus on data showing the

grid’s support of competitive markets.74 Among these

historical data series are:

• Grid access and generator connection

• Cost and quality of transmission service

• Load pockets and transmission bottlenecks

• Congestion costs

• Seams costs (trade barriers)

• Economic trade and regional price differences.

Accessrefers to a generator’s ability to put power into the

grid. Denial of service forces generators out of the market. Statistics on access requests and service denials

show the grid’s support of generator competition and

can reveal unequal treatment of market participants.

Generator connection data show the grid’s accommodation of new entrants—all eventually requiring access in

order to compete.

Quality of transmission service refers to the different types

of service available to customers. Types of service

include point-to-point or network, and firm or interruptible. Firm service all but guarantees reliable transmission service, whereas interruptible service can be

suspended (curtailed) for a variety of economic and

operational reasons. In most of the United States, firm

service is negotiated between transmission owners and

customers. In the Pennsylvania-New Jersey-Maryland

(PJM) Interconnection and the New York ISO, transmission service is firm if customers agree to pay applicable

congestion charges. In PJM, customers can buy financial

transmission rights (FTRs), also called fixed transmission rights, which allow the holder to recover congestion

charges incurred in flowing power between the two

points specified in the FTR.

Generators need firm service to sell into ISO capacity

markets and to assure customers that their contracted

energy will be delivered.75 Data showing that firm transmission service is increasingly available and less costly,

and that curtailments are decreasing, would be evidence

that the grid’s performance in supporting commerce is

improving.

Bottlenecksrefer to constraints on the grid’s physical ability to deliver power while respecting security limits.

Congestion costs are a measure of the cost of these limits.

Data showing temporal declines in bottlenecks and congestion costs would indicate that transmission is becoming less of a constraint to market integration and

competition.

Seams costs refer to administrative, coordination, and

other institutional obstacles to trade between control

areas. To ensure reliability, control-area operators

require the sending and receiving parties to schedule

power flows and agree on price and other terms in

advance. Outsiders typically must make scheduling

arrangements and pay fees that insiders do not face. PJM

imposes a fee for exporting power outside its borders.

These coordination and pricing arrangements—“seams

issues”—increase the cost of moving energy between

markets and limit market integration.

Economic trade refers to the movement of power between

markets in response to price differences. Economic trade

within and across regions is a powerful force both for

limiting the ability of local producers to raise prices and

for efficient resource allocation. When the local price of

petroleum and other energy sources exceeds the outside

price by more than transportation costs, imports

increase. By analogy, data showing large volumes of

electricity flowing regularly from lower to higher price

areas would suggest that the grid is supporting

competition.

Matters are not so simple, however, with electricity. As

mentioned in Chapter 2, electricity on an AC system cannot be directed from individual generators to individual

customers. Instead, generators put power onto the grid

and their customers take power off the grid. Some

power flows across boundaries are inadvertent, and

although these “loop flows” do not represent commercial transactions, they can be large.

Another minor complication is that electricity can flow

from higher priced to lower priced areas. In extreme

cases, which do occur in practice, customers are paid for

taking more power. This inversion of normal commercial practice happens because transmitting power to

lower price areas can at times reduce even higher congestion costs elsewhere on the grid.

Even with these anomalies, data showing a strong tendency for significant volumes of power to flow in the

direction of higher price would suggest that the grid is

supporting economic trade. Increasing economic trade

and narrowing price differences would be consistent

38 Energy Information Administration / Electricity Transmission Data

74Competitive markets are characterized by a large number of independent suppliers vying to sell to a large number of informed customers. See Chapter 5.

75Customers can be responsible for acquiring transmission capacity. Load-serving entities can purchase FTRs to insure their agreements

with generators.
with improvement in the grid’s support of market

competition.

However useful these data are for identifying market

trends and documenting current conditions, they can

only record what has already happened. By themselves

they are imperfect guides to how electricity market size

and trade potential change in response to changes in the

grid’s configuration, its management, and its economic

organization. Valid inferences about the quantitative

impact of future and hypothetical conditions require

realistic electrical models.

Data Showing the Grid’s

Support of Markets

Access

FERC’s OASIS is the primary source of data on grid

access, available capacity, transmission rates, and other

aspects of transmission. Each public utility or its agent

that owns, controls, or operates transmission facilities in

interstate commerce is required to post data prescribed

by FERC on a web site and to make them available to

market participants, FERC, State regulators, and the

public.76 FERC requires the data to be available on the

site for 90 days and to be retained for 3 years. FERC itself

does not maintain a single consolidated web site for

transmission data.

There are currently 22 OASIS web site nodes that serve

as gateways to 168 transmission provider web sites.77

Two of the nodes and six of the provider sites are in Canada. The number of firms listed in a node varies: the

Western States Coordination Counsel (WSCC) lists 30

transmission providers; the East Central Area Reliability

(ECAR) node lists 3. Some transmission providers not

regulated by FERC (nonjurisdictional entities) voluntarily maintain OASIS web sites, including 8 firms in the

Electric Reliability Council of Texas (ERCOT), the

Bonneville Power Administration, the Western Areas

Power Administration, the Sacramento Municipal Utility District, and the Tennessee Valley Authority.

Entergy’s OASIS site illustrates the kind of data that are

available. The site contains information on type of service, volume, and number of hours requested; price of

service; affiliation with Entergy; and whether the

request was granted. Table 14 reports the disposition of

1,216 requests for non-firm, point-to-point service

requested through Entergy’s OASIS site for the month of

June 2003. About 96 gigawatts of transmission capacity

was requested by 24 entities, of which a total of 3.7

gigawatts (about 4 percent of the total requested) was

refused. Of the 24 companies requesting service, 2 were

affiliates of Entergy, which jointly filed 696 (57 percent)

of the requests, leaving 22 unaffiliated entities with 520

requests. The volume of capacity reservations requested

by Energy affiliates averaged twice the volume

requested by non-affiliates. Non-affiliates were refused

more capacity in aggregate, and their total of 1,870

megawatts refused constituted 7 percent of their total

capacity requests.

Although FERC mandates their minimal content, OASIS

web sites vary considerably in their look and feel. As

part of the research for this report, the author asked

FERC staff to extract comparable data from several

OASIS sites. The FERC analysts reported that identical

queries succeeded or failed depending on the site: each

site had its own language; some sites would not allow

data to be downloaded; and some sites would not permit downloading data in a standard “.cvs” or spreadsheet file. There is no official database that maintains

and archives time series of the information on the OASIS

sites.

New Generator Entry

Form EIA-860 reports when generators connect to the

grid and their major characteristics, including location,

size, primary fuel consumed, and ownership. Table 15

reports 173 gigawatts of new capacity—most of it gasfired combined-cycle and turbine units—added from

Energy Information Administration / Electricity Transmission Data 39

Table 14. Non-firm Point-to-Point Transmission Service Provided by Entergy in June 2003

Entities Requesting Service Service Requests Megawatts Requested

Type Number Total Refused Total Refused

Average

Requested

Average

Refused

Percent

Refused

Affiliates. . . . . . 2 696 20 69,134 1,793 99 90 2.6

Non-Affiliates. . 22 520 27 26,727 1,870 51 69 7.0

Total . . . . . . . 24 1,216 47 95,861 3,663 79 78 3.8

Source: Entergy OASIS web site, http://oasis.e-terrasolutions.com/OASIS/EES.

76See Federal Energy Regulatory Commission, Open Access Same-Time Information System and Standards of Conduct, Order No. 889, Final

Rule, 18 CFR Part 37 (April 24, 1996); and Standards and Communications Protocols for Open Access Same-Time Information System (OASIS), Version 1.4, Docket No. RM95-9-014 (January 26, 2000).

77The web site address of the central clearinghouse is www.tsin.com.
1995 through 2002.78 This represents a 23-percent

increase over the 1994 national total capacity of 763

gigawatts.79 The table also shows that most of the capacity expansion has occurred in the nonutility sector, specifically among iIPPs that do not own transmission

facilities.

Figure 7 shows that the new units are widely distributed

by NERC region. The Southeastern Electric Reliability

Council (SERC), already the region with the largest

amount of generation capacity, added the most new

generating capacity, with more than a quarter of the

total new capacity. ECAR’s expansion was roughly proportionate to its size, whereas ERCOT added a disproportionately large amount of new capacity relative to

existing capacity. These developments reflect in part the

replacement of older, less efficient steam units with new

combined-cycle technology. California (CaliforniaSouthern Nevada Power), in response to the crisis of

2000-2001, showed much greater activity in 2001 and

2002 than it had from 1995 though 2000. The New York

ISO reports relatively little additional new capacity,

indicating that either new units or expanded access to

transmission will be needed to meet increasing demand

in the next few years.80

EIA data show neither how much generators pay to connect (direct and for system enhancements), nor the time

required between application for service and connection. EIA’s connection data are in the public domain.

Cost and Quality of Transmission Service

OASIS is also the primary source of data on the availability and cost of firm and interruptible service. Entergy’s

web site again provides an example, as shown in Table

16.81 Entergy does not offer long-term non-firm service

or hourly firm service. In addition to the charges specified in Table 16, transmission customers must purchase

ancillary services from Entergy at its posted rates and

make up for transmission losses with additional generation (3 percent of the delivered volume).

What is not available on OASIS is how much individual

generators and load-serving entities actually pay for

transmission of wholesale energy.82 In some areas the

costs include explicit congestion fees and the costs of

transmission rights in addition to the types of charges

Entergy lists. Annual statistics on the quantity of power

that utilities wheel and revenues from wheeling are

available, as discussed in Chapter 3. It is not possible to

tell, however, whether average annual data accurately

represent the charges wholesale customers face at peak

times, seasonally, or at all locations served by the service

provider.

OASIS does not identify how much of each market participant’s generation or demand volume is covered by

firm transmission service. Although a customer has

arranged for transmission service, either firm or interruptible, the power may not be delivered; i.e., it may be

40 Energy Information Administration / Electricity Transmission Data

Table 15. New Generating Capacity Added by Type of Ownership, 1995-2002

(Megawatts Summer Capacity)

Year

Investor-Owned Publicly Owned

Independent Power

Producers Other Nonutility Total

Capacity

Number of

Units Capacity

Number of

Units Capacity

Number of

Units Capacity

Number of

Units Capacity

Number of

Units

1995 3,774 53 1,212 40 530 53 2,165 81 7,681 227

1996 2,205 43 2,676 63 480 44 2,148 75 7,510 225

1997 1,247 18 811 44 309 61 1,257 44 3,623 167

1998 636 14 602 61 597 68 1,612 50 3,447 193

1999 1,788 24 1,472 132 5,686 138 1,565 57 10,511 351

2000 5,046 83 2,253 114 17,707 243 2,319 58 27,325 498

2001 6,904 62 3,744 111 25,248 370 6,669 62 42,565 605

2002 4,210 30 5,353 174 52,000 553 8,735 67 70,298 824

Total 25,809 327 18,124 739 102,556 1,530 26,470 494 172,960 3,090

Source: Energy Information Administration, Form EIA-860.

78Energy Information Administration, Form EIA-860, “Annual Electric Generator Report” (2002).

79Energy Information Administration, Electric Power Annual 2001, DOE/EIA-0348(2001) (Washington, DC, March 2003), Table 2.1.

80See, for example, New York Independent System Operator, “Power Alert II: New York’s Persisting Energy Crisis” (March 27, 2002);

and “Power Alert III: New York’s Energy Future” (May 2003), web site www.nyiso.com.

81Entergy’s open access transmission tariff, filed March 20, 2001, is also available on its OASIS web site, http://oasis.e-terrasolutions.

com/OASIS/EES.

82EIA collects data on delivery charges and megawatts delivered to unbundled retail customers on Form EIA-861, Schedule 4, Part C.
curtailed. Chapter 2 reports that NERC’s TLR system

records—but does not routinely report—curtailment

data, and data are available only for the Eastern Interconnect. Trends in the frequency and size of curtailments are measures of the quality of transmission

service.

Bottlenecks

ISOs, transmission owners, and market participants

are generally knowledgeable of bottlenecks, although

documented analyses of these constraints are available

mainly from ISOs. NERC’s periodic reliability assessments (see Chapter 2) identify load pockets and bottlenecks. To some extent, NERC’s identifications are based

on publicly available TLR data; but the analytical basis

NERC uses for identifying other bottlenecks is not generally available.

Under contract to DOE, the Consortium for Electric Reliability Technology Solutions (CERTS) surveyed six

ISO/RTOs to identify bottlenecks and load pockets in

their areas.83 The results for five of those regions, summarized in Table 17, are representative of the kinds of

data available from those organizations. The CERTS

study also reported estimates of costs for some of the

projects to relieve congestion, as shown in Table 18. It

did not report how much those investments would be

expected to save.

Energy Information Administration / Electricity Transmission Data 41

ECAR ERCOT PJM MAIN MAPP NYISO ISO-NE FRCC SERC SPP NWPP RA CNV

0

10,000

20,000

30,000

40,000

50,000

Megawatts Summer Capacity

1995

1996

1997

1998

1999

2000

2001

2002

Figure 7. New Generating Capacity Added by NERC Region, 1995-2002

Source: Energy Information Administration, Form EIA-860.

Table 16. Entergy Transmission Service Rates as of June 1, 2003

Service

Firm Non-Firm

Price Unit Price Unit

Hourly On-Peak (Hour Ending 0700 Through

Hour Ending 2200, Monday Through Friday). . — — $3.15 Megawatthour

Hourly Off-Peak (All Other Hours) . . . . . . . . . . — — $1.50 Megawatthour

Daily On-Peak (Monday Through Friday). . . . . $50.00 Megawatt-Day $50.00 Megawatt-Day

Daily Off-Peak (Saturday and Sunday) . . . . . . $36.00 Megawatt-Day $36.00 Megawatt-Day

Weekly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $252.00 Megawatt-Week $252.00 Megawatt-Week

Monthly. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,090.00 Megawatt-Month $1,090.00 Megawatt-Month

Long Term (1 Year or Longer) . . . . . . . . . . . . . $1,030.00 Megawatt-Month — —

Source: FERC staff, compiled from Entergy’s OASIS web site.

83Consortium for Electric Reliability Technology Solutions, U.S. Department of Energy Transmission Bottleneck Project Report (March 19,

2003).
Many transmission bottlenecks cannot be identified

with TLR data, for a variety of reasons:

• TLRs are not used to manage congestion in the West.

• A TLR may indicate overbooking rather than a physical limit (overbooking is mainly a reflection of the

limits to accurate forecasting of transmission

requirements).

• Systems trying to facilitate trade may attempt to

operate close to their security limits, and systems not

encouraging trade may understate how much transmission capacity is available.

• TLRs have not been exercised in the Southeast but

are common in the Midwest. Commentators disagree on the reasons for the differences.84

Congestion Costs and Revenues

Congestion costs and revenues are measured in at least

three ways. System redispatch cost is the increase in total

system operating cost due to congestion to meet a fixed

level of demand. Redispatch costs are typically captured

in uplift charges. Mainly these charges occur because

higher cost, but better located, generators must be run to

get around transmission constraints. The economic cost of

congestion is the loss in net benefit, which is the same as

uplift cost when demand does not depend on price. Congestion revenue is the difference between the prices at the

sending and receiving ends times the volume of flow on

the line. Congestion revenue is analogous to a transportation charge but is in fact a particular kind of scarcity

rent. The location-specific prices needed to calculate

congestion revenues are generally available for only a

few areas, notably the northeastern ISOs. Several organizations have reported the aggregate of some redispatch

costs and congestion revenues.

It is rarely necessary to curtail generation under

locational prices, because locational prices equate supply and demand in such a way that all transmission limits are met, and they are adjusted in real time in response

to system conditions. In the rest of the Eastern Interconnection, service curtailments are used to enforce transmission limits. Thus, observed wholesale prices (when

available) do not reflect current transmission constraints: the prices net of transmission charges in the

sending area are too high and those in the receiving area

are too low. The congestion revenue (observed price

42 Energy Information Administration / Electricity Transmission Data

Table 17. Major Bottlenecks in Five ISO/RTO Regions

Region Widespread Grid Reliability Problems Risk of Significant Consumer Cost

CAISO . . . . San Diego Area and the San Francisco Peninsula Path 15

ERCOT . . . — South to North Texas and South Texas to Houston

NYISO . . . . — Central East, Leeds-PV and New York City/Long Island Cable

Interface

ISO-NE . . . Southwest Connecticut to Norwalk, Northeast

Massachusetts/Boston Area, and Northwest Vermont

—

PJM . . . . . . — Northwest Pennsylvania, West of Washington, DC, Delmarva

Peninsula, West and East 500-kV Interface

Source: Consortium for Electric Reliability Technology Solutions, U.S. Department of Energy Transmission Bottleneck Project Report (March 19,

2003).

Table 18. Estimated Project Costs for Partial Relief of Congestion

Region Project

Estimated Cost

(Million Dollars)

CAISO . . . . Path 26 306

Imports to San Diego 252

ERCOT . . . Two 345-kV lines from West Texas to North Texas 140

MISO . . . . . Substantially increase bulk power transfer capability 7,000

Gains Substation: add a second 345/138-kV transformer bank needed to serve load growth in the area of

Grand Rapids, Michigan 7

NYISO . . . . Marcy-New Scotland 345-kV circuit: line originally built for 765 kV could be converted from single to double

circuit 75

Rebuild two 115-kV lines out of Leeds to 345 kV 225

ISO-NE . . . Build a 345-kV loop around the southwestern Connecticut area (Phase 1 and 2) 600

Reinforce northwest Vermont load pocket 125

PJM . . . . . . Add 500/230-kV transformers at Doubs Substation (Northwest of Washington, DC) 22

Source: Consortium for Electric Reliability Technology Solutions, U.S. Department of Energy Transmission Bottleneck Project Report (March 19,

2003), p. 17.

84See, for example, L. Canto et al., “Beware Transmission Data—Often They Are Not What They Seem To Be” (Cambridge Energy

Research Associates, June 2003).
Energy Information Administration / Electricity Transmission Data 43

Redispatch Costs, Congestion Revenues, and Congestion Cost

Redispatch costs, congestion revenues, congestion cost

(loss of producers’ and consumers’ surplus), and uplift

costs are caused by constraints on the transmission

grid’s ability to move power from lower to higher cost

areas. The following examples illustrate those

concepts.

Panel A shows two regional supply curves (marginal

cost curves, MC1 and MC2); the thick line is the market

supply curve. For simplicity, assume all demand is in

Region 2. If there were a limit on power transfers

between Regions 1 and 2 of 100 MWh, the aggregate

supply curve in Region 2 would be that shown in Panel

B. Up to 50 MWh, Region 2 meets its demand with its

lowest cost generators; for demand levels up to 150

MWh, those generators are supplemented with

imports from Region 1.

When demand exceeds 150 MWh, for example 240

MWh as shown in Panel C, imports cannot be

increased, and Region 2 has to run its higher cost generators, illustrated by the upward sloping curve. If

there were no transfer limit, the supply curve in Region

2 would extend the flat section between 50 MWh and

150 MWh indefinitely. Redispatch cost is the difference

between the lowest cost of meeting demand with and

without the line constraint. When demand is fixed,

redispatch cost is the economic cost of congestion.

Redispatch cost is shown in Panel C as the area RDC.

Congestion causes consumer expenditures to increase

by more than redispatch costs. Marginal cost in Region

2 is P2 and marginal cost in Region 1 remains at MC1 =

P1. In a competitive market, price equals marginal cost.

Congestion, together with marginal cost pricing,

causes consumer expenditures to grow from P1 x 240 in

the unconstrained case to P2 x 240, for an increase of

(P2 - P1) x 240. As shown in Panel C, the additional

expenditures go to generators as increased profit (areas

A and B) and compensation for redispatch costs (area

RDC). The remaining portion of the increased expenditures goes to transmission owners (or holders of financial transmission rights) as congestion revenues,

indicated by area CR, which is the price difference

times the flow, (P2 - P1) x 100.

When demand is sensitive to price, congestion reduces

the benefits from consuming electricity. Because congestion increases the price of electricity, customers consume less and forgo the benefits of maintaining their

electricity use. The economic cost of congestion is the

sum of lost consumer benefits and redispatch costs.

Those are shown in Panel D as the sum of the areas

under RDC (redispatch cost) and LCB (lost consumer

benefit).

Uplift charges are the specific fees that systems use to

compensate generators for agreeing to be redispatched. How the amount of these uplift charges is

determined varies. In the United Kingdom’s original

pool, generators who are not allowed to produce as

much as they would like at the uniform system price

are paid an estimate of their forgone profit; those

required to produce more at the uniform price are paid

to cover their additional costs. Whatever cost/profit/

loss scheme is used to compensate generators, the

increased revenue from customers is more than adequate to fund the payments.

50 MWh 150 MWh

$/MWh

MC1

Panel B

50 MWh

$/MWh

MC1

MC2

Panel A

50 MWh 150 MWh 240 MWh

$/MWh

RDC

Panel C

A B CR

P1

P2

50 MWh 150 MWh

$/MWh

RDC

Panel D

Demand LCB
difference times flow) calculated with observed prices is

too low. In an attempt to correct for the understatement

of congestion revenue, FERC and the New York ISO

have estimated system redispatch costs in the receiving

area, then added the estimate to observed congestion

revenue. Table 19 summarizes estimates from four

ISOs for their areas, and from FERC for the Eastern

Interconnection.

Except for the FERC study cited above, official data do

not report estimates of redispatch costs, congestion

costs, or congestion revenues outside the ISOs. The estimates available for ISOs are mostly an incomparable collage of uplift charges, redispatch costs, congestion

revenues, and a total consisting of some redispatch costs

and some congestion revenues.

Seams Costs

There are no official data, except possibly for the ISOs

and RTOs, that show the actual costs (direct and indirect) uniquely associated with moving power across

control or ownership boundaries. Price differences

between the sending and receiving areas may reflect,

but do not identify, the particular costs of crossing

boundaries.

Economic Trade and Regional

Price Differences

Economic trade is undertaken to profit from price differences between areas. The basic data for documenting

economic trade are wholesale price differences and the

corresponding trade flows.

Wholesale trade is a mix of very short-term and longterm transactions. Most wholesale trade occurs in private markets, and the prices are not publicly available.85

Table 20 shows EIA data on sales for resale— essentially,

wholesale trade. In the 6 years following FERC Order

888, wholesale trade on the part of utilities, IPPs, and

combined heat and power generators increased by 65

percent, at a continuously compounded growth rate of

8.4 percent per year.

Northeastern ISOs and California have public real-time

markets for wholesale energy and publicly report prices.

The northeastern ISOs also have day-ahead markets

with publicly reported prices. As shown in Table 21,

spot markets (“real-time” markets) are an important

source of supply in the northeastern ISOs.

PJM reports relevant price and power flow data for its

trade with the New York ISO. About 85 percent of PJM’s

44 Energy Information Administration / Electricity Transmission Data

Table 19. Summary of Congestion Costs Reported by ISOs and FERC

Region Period

Congestion Costs

(Million Dollars) Cost Calculation Method

PJM [1] . . . . . . . . . . . . . 1999 53 Congestion revenues

PJM [1] . . . . . . . . . . . . . 2000 132 Congestion revenues

PJM [1] . . . . . . . . . . . . . 2001 271 Congestion revenues

PJM [2] . . . . . . . . . . . . . 2002 430 Congestion revenues

ISO-NE [3]. . . . . . . . . . . 5/1999-4/2000 99 Uplift chargesa

ISO-NE [3]. . . . . . . . . . . 5/2000-4/2001 120 Uplift chargesa

ISO-NE [4]. . . . . . . . . . . 2003 50-300 System redispatch payments

CAISO [5] . . . . . . . . . . . 2000 391 Congestion revenues

CAISO [5] . . . . . . . . . . . 2001 107 Congestion revenues

CAISO [6] . . . . . . . . . . . 2002 42 Congestion revenues

NYISO [7] . . . . . . . . . . . 2000 1,240 System redispatch payments + congestion revenues

NYISO [7] . . . . . . . . . . . 2001 570 System redispatch payments + congestion revenues

NYISO [8] . . . . . . . . . . . 2000 517 Congestion revenues

NYISO [8] . . . . . . . . . . . 2001 310 Congestion revenues

NYISO [9] . . . . . . . . . . . 2002 525 Congestion revenues

FERC [10] . . . . . . . . . . . 6/2000-8/2000 891 System redispatch payments (partial) + congestion revenues

a

ISO New England’s congestion cost calculation method was modified in March 2003.

Sources: [1] PJM Interconnection, State of the Market Report 2001; [2] PJM Interconnection, State of the Market Report 2002; [3] ISO New England (ISO-NE), Annual Markets Report; [4] ISO New England, RTEP02; [5] California Independent System Operator (CAISO), Market Analysis

Reports; [6] CAISO, 2002 Annual Report on Market Issues and Performance; [7] New York Congestion and Physical Constraint Cost Estimates; [8]

2001 Annual Report on the New York Electricity Markets; [9] 2002 State of the Market Report: New York Electricity Markets; [10] Federal Energy Regulatory Commission (FERC), Electric Transmission Constraint Study. Detailed source citations are provided in the report from which this table was

adapted: B.C. Lesieutre and J.H. Eto, Electricity Transmission Congestion Costs: A Review of Recent Reports (October 2003), DOE Contract No.

DE-AC03-76SF0098.

85FERC’s new “Electric Quarterly Report” (EQR) collects prices associated with individual wholesale trades. It may be possible to use

those data to estimate market prices for specific regions. In addition to volumes, EIA collects annual data on revenues from sales for resale.

Dividing revenue by volume yields a volume-weighted average annual price, or the same thing, average revenue for sales for resale.
gross imports and 93 percent of its exports occur in the

real-time market. Differences in spot market prices at the

borders are clearly appropriate for valuing trade opportunities.86 In addition to spot prices, PJM reports net

exports to New York. Because both have locational

prices, it is possible to calculate the differences between

the PJM and New York market prices at the borders and

to associate price differences with power flows.

During 2002, monthly exports to the New York interface

ranged from about 100,000 megawatthours in June, to

more than 1,500,000 megawatthours in November.

Importantly, the volume of exports generally increases

as the monthly average hourly difference between the

New York and PJM prices—the price differential—increases. Figure 8 shows the export volume to

New York and the average hourly price differential for

2002. That exports increase along with the price differential suggests that competition is working to some extent.

It does not explain why there is a significant price

differential.

The data do not support similar displays for other ISOs.

California’s adjacent markets do not report market

prices in official data. ERCOT does not trade outside

its boundaries. New England and New York have

Energy Information Administration / Electricity Transmission Data 45

Table 20. Wholesale Electricity Trade

(Sales for Resale), 1990-2002

(Thousand Megawatthours)

Year Sales for Resale

1990 1,115,946

1991 1,250,314

1992 1,284,273

1993 1,387,137

1994 1,387,966

1995 1,495,015

1996 1,656,090

1997 1,838,539

1998 1,914,916

1999 1,977,753

2000 2,325,652

2001 2,893,382

2002 2,747,015

Source: Energy Information Administration, Electric Power Annual

2001, p. 36, and Electric Power Annual 2002, p. 34. Includes utilities,

IPPs, and combined heat and power generators; excludes marketers.

Table 21. Spot Market Sales as a Percentage of

Total Demand, 1999-2002

Year New England New York PJM

1999 13a — 15

2000 23 41 18

2001 24 47 21

2002 32b 48 — a

May-December.

b

January-November.

Sources: ISO New England, Monthly Market Report (December,

1999-2002); New York Independent System Operator, Monthly Report

(December, 2000 and 2002); PJM, State of the Market Report

(1999-2001).





 













 







 

 



















 



 

 



Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

2002

0

500

1,000

1,500

2,000

Volume

(Thousand Megawatthours)

0

5

10

15

20

25

30

-5

Monthly Average Price Difference

(Dollars)

PJM/NYIS Export

PJM/NYIS Import

NYC Zone-PJM NY Interface

NYW Zone-PJM NY Interface

NY PJM Interface-PJM NY Interface







Figure 8. Price Differential and NYISO Export Volume, January-December 2002

Source: PJM, State of the Market Report (2002), p. 67.

86PJM Interconnection, “2002 State of the Market,” p. 62.
substantial trade with Canada at negotiated prices. New

England trades with New York but, until recently, did

not use locational prices. Consequently, the “at-theborder” price differences do not necessarily reflect economic values. There are no official wholesale market

price data for PJM’s trading partners outside New York.

Other than those reported by ISOs, wholesale electricity

prices are not publicly available. EIA does not collect

data on wholesale electricity prices except as a volumeweighted average price (total revenue divided by volume sold), which does not accurately reflect actual market prices. The volume-weighted calculation includes

data from transactions under long-term contracts that

do not reflect current market prices, and it does not

incorporate the impact of ongoing changes in market

prices, including hourly, daily, and seasonal swings.87

FERC is now attempting to collect the prices associated

with individual spot markets and long-term contracts in

its “Electric Quarterly Reports.”88 It is too early to tell

whether the data can yield good approximations of market prices in areas lacking formal markets. Outside the

ISOs, official power flow data are of uneven quality.

International import data illustrate some of the problems in estimating power flows across boundaries. Canada has long been an important supplier of low-cost

electricity to the United States, much of it generated

from hydropower, but it is not clear how much has been

supplied. Data on international electricity trade with

Canada (and Mexico) are collected and reported on an

annual basis by DOE on Form FE-781R, “Annual Report

of International Electrical Export/Import Data,” and by

Canada’s National Energy Board (NEB). The NEB collects information directly from market participants,

many of whom trade power under long-term contracts

utilizing Presidential Permits. As illustrated in Table 22,

the volumes reported by NEB generally are greater than

those reported by DOE, and the differences are too large

to be explained by differences in metering.

Except for PJM and New York, official data cannot be

used to show the extent or growth of economic trade.

Outside the northeastern ISOs it is not possible to show

that wholesale price differences are narrowing.

Filling the Information Gaps

With the important exception of wholesale price and

quantity, much of the data needed to evaluate the transmission grid’s support of markets is already being collected. EIA collects comprehensive data on generators,

including those planning to connect to the grid. Those

data are indispensable for analyzing the potential supply of electricity, generator entry to the market, and market shares (see Chapter 5). OASIS data are critical to

evaluating access, transmission tariffs, and the quality of

service (firm or interruptible, point-to-point or network). NERC has data on power flows across the

high-voltage grid and on curtailments. The ISOs are

reporting congestion.

OASIS and NERC data are either unusable, unavailable

to the Federal Government on a routine basis, or both.

The OASIS data are scattered across dozens of web sites,

are neither edited nor archived, and are not in useable

form. NERC’s power flow and curtailment data are not

routinely available for the government’s monitoring of

wholesale trade. Congestion data, trade flows, and market price differentials are only available for the ISOs.

Each ISO defines and makes the data available (or not)

differently. Table 23 provides suggestions for modifying

existing data collection forms and web sites to make

them more applicable to the Federal Government’s

monitoring responsibilities.

46 Energy Information Administration / Electricity Transmission Data

Table 22. Comparison of Electricity Transactions Reported by the U.S. Department of Energy (DOE) and

Canada’s National Energy Board (NEB), 1997-2001

(Billion Kilowatthours)

Year

U.S. Imports from Canada U.S. Exports to Canada Net U.S. Imports

DOE NEB DOE NEB DOE NEB

1997 47.83 43.06 15.56 7.47 32.37 35.59

1998 45.41 39.50 15.95 11.68 29.46 27.82

1999 38.56 42.91 12.28 12.95 26.28 29.96

2000 43.68 48.52 11.24 12.68 32.44 35.84

2001 31.12 38.40 12.36 16.10 18.77 22.30

Sources: DOE: U.S. Department of Energy, Form FE-781R, “Annual Report of International Electrical Export/Import Data.” NEB: National Energy

Board, web site www.neb.gc.ca/stats/elec/index_e.htm.

87These distortions frequently go unrecognized. See, for example, L. Lynch, “An Unfair Jolt to Consumers,” San Francisco Chronicle

(December 12, 2003), in which the figure description identifies average revenue as price; and U.S. General Accounting Office, Electricity

Restructuring, GAO-03-586, Appendix 1, p. 49, which asserts that Form EIA-826 “. . . is the only timely source of information on the price and

volume of power sold . . . .” The reference is to volume-weighted price revenue, not market price.

88Federal Energy Regulatory Commission, Revised Public Utility Filing Requirements, Order No. 2001, Final Rule, 18 CFR Parts 2 and 35

(April 25, 2002).
Nationwide data on seams costs could only be obtained

with a new data collection. Data on cost and quality of

transmission service could be obtained either by modifying the data that utilities are required to report on

OASIS or by adding reporting categories to existing EIA

forms.

Some of the data needed to monitor the transmission

grid’s support of markets may become available in the

course of meeting other needs. The government’s ability

to analyze the physical basis for load pockets and bottlenecks, and to determine what investments would mitigate them, depends on its having access to high-quality

power flow models. The government may decide to

build and maintain such models for reliability or

national security reasons and make them available for

public policy analysis. If so, there would be no need for

additional, specialized models to study load pockets

and bottlenecks.

Outside the ISOs, spot market prices and associated

quantities, including interregional trade flows, are not

available. FERC’s new EQR does record transaction

prices and quantities for “long term” and “short term”

transactions, but they are not the same as the spot market prices reported by the ISOs. It is too early to know

whether the EQR data can yield accurate estimates of

market prices comparable to those in the ISOs. If not, a

new collection would be required to obtain wholesale

prices and associated quantities. Significant research

and effort would be required in order to collect the

information.

Energy Information Administration / Electricity Transmission Data 47

Table 23. Transmission and Wholesale Power Market Data: Possible Changes to Existing Forms

Information Need Form Needed Changes Comment

1. Access time series

data by provider.

OASIS Consolidate, edit, and archive all data required on OASIS

in a single database.

2. Transmission

service offerings

and actual rates.

OASIS As above.

3. Cost and time

required for

generator

connection.

EIA-860 Report how much generator paid for grid reinforcements,

direct (other) connection costs, and the date of the initial

connection request.

For newly activated generators, add

questions to Schedule 3, Part B,

Line 4.

4. Load-serving entity

cost and quality of

transmission

service.

EIA-861 Report percent of supply covered by long-term contracts,

percent covered by firm service (or financial transmission

rights), transmission service expense, and curtailments

(megawatthours) of firm and non-firm service in past year.

Schedule 2, Part B.

5. Generator cost

and quality of

transmission

service.

EIA-906 Report paralleling that of load-serving entities (see above).

6. Congestion costs,

trade flows and

price differentials.

ISO

web sites

FERC and ISOs define data elements the same way

across ISOs and report data to FERC.

None of this information is available

for analyzing the effect of restructuring

policy outside the ISOs.

5. Wholesale Competition

Introduction

Chapter 4 reviewed information relevant to the electricity transmission grid’s support of wholesale markets.

This chapter considers the information available to

determine whether wholesale markets are competitive.

Competitive markets are desirable because they promote the efficient allocation of resources.89 The Federal

Government is responsible for approving utility mergers and for enforcing antitrust law, as well as wire fraud

and conspiracy statutes incident to recent prosecutions

for electricity market manipulation.

Somewhat surprisingly, competitive wholesale electricity prices are also necessary for properly valuing congestion revenues and, thereby, providing signals for

transmission investment and new generator location.

Congestion can be reduced by investments in transmission capability and by locating new generators to relieve

bottlenecks. When energy prices are competitive, the

transmission price (difference in energy price at either

end of a line) is the marginal benefit (savings) from

relieving congestion. Consequently, when wholesale

prices are competitive, the congestion charge is appropriate for signaling the (marginal) need for investment

and for guiding the location of new generation. The Federal Government’s interest is not to determine where

lines and generators should be located but rather to give

State government and private decisionmakers information about the resource consequences of their decisions.

The next section, “Measures of Wholesale Competition,”

presents conventional statistics that have been accepted

by Federal courts for describing competitive markets.

The section that follows, “Data on Wholesale Competition,” identifies the Federal Government’s capabilities

for monitoring and evaluating wholesale competition in

the electricity industry. The chapter concludes with a

section on “Filling the Information Gaps,” which discusses how gaps in existing data collections might be

filled.

Measures of Wholesale Competition

At any particular time, competitive markets are characterized by a large number of suppliers vying to sell to a

large number of informed customers. When there are

many buyers and sellers, each of whom is small relative

to the market, no one has significant power over price. In

those circumstances, the market price is one that causes

demand to equal supply, and price approximately

equals the cost of producing the last unit sent to market—the marginal cost.90 Price also equals the marginal

benefit received by the last customer willing to make a

purchase. A supplier has market power when he can

sustain a price that is significantly above marginal cost.

Economists often use the notion of long-run competition

to capture the idea that free entry and exit of competitors

would eliminate excessive profits. In classical analysis,

that would mean not only that price would equal marginal cost but also that price would equal minimum

average cost. Minimum average cost includes a normal

rate of return on capital. Modern formulations of the

idea of long-term equilibrium refine this idea to consider

“lumpy” capacity increments, the number of ideally

sized firms relative to the market, and technical problems in defining least average cost for some production

processes.91 Without free entry and exit of independent

firms, price could equal marginal cost (an efficiency condition), but profits would be supernormal, indicating

under-investment in the industry.

Number of Competitors, Concentration

Ratios, and New Entry

The number of firms serving a regional market, their

market shares, and market share indices—especially the

Herfindahl-Hirschman Index (HHI)—are well-established indicators of a competitive industry.92 These measures assume that the relevant market can be identified.

The difficulty in calculating market shares and HHIs in

the electricity industry is that market boundaries are not

Energy Information Administration / Electricity Transmission Data 49

89Efficient in the sense that a competitive wholesale power market would minimize the social cost of meeting consumers’ electricity

demands, and those demands would reflect the value to consumers of consuming electricity relative to the value of consuming other goods.

Stated differently, competition has the potential to maximize the net benefit from electricity consumption, less the costs of its production

and delivery.

90Price might not equal marginal cost when some production inputs are “lumpy.”

91See, for example, A. Mas-Colell, M.D. Whinston, and J.R. Green, Microeconomic Theory (London, UK: Oxford University Press, 1995),

pp. 334-341.

92See U.S. Department of Justice and U.S. Federal Trade Commission, “Horizontal Merger Guidelines,” Section 1—Market Definitions,

Measurement and Concentration (issued April 2, 1992; revised April 8, 1997), web site www.usdoj.gov/atr/public/guidelines/

horiz_book/hmg1.html.
obvious, and establishing boundaries generally requires

electrical models. As discussed in Chapters 2 and 4, the

Federal Government does not maintain reference electrical models sufficient for delineating regional markets.

While the courts pay attention to the HHI, they also consider many other factors before concluding that a firm is

exercising market power.

Price Compared to Marginal Cost

Market price compared to marginal cost is a litmus test

for competition: wholesale price sustained above the

marginal cost of the last generator dispatched can indicate market power. This comparison, called the Lerner

index, is variously calculated as the ratio of price to marginal cost, the percent markup over marginal cost, or the

markup as a percentage of price.93 Accurately estimating and interpreting the Lerner index is often a

challenge.

To make a valid comparison, reference prices and marginal costs must refer to the same period of time. This is

important in the electricity industry because prices

typically fluctuate significantly during the day. An

example of hourly prices at the Pennsylvania-New Jersey-Maryland Interconnection (PJM), as shown in

Figure 9, is illustrative of the magnitude of price

variation.

Accurate estimates of marginal cost are also critical to

the results. As pointed out by Timothy Brennan, many

power market studies have used average variable cost

rather than true marginal cost, thus overstating the

extent of market power and perhaps influencing regulators to enforce artificially low price ceilings.94

Selecting the right marginal cost to use in the Lerner

index also requires care. When transmission is unconstrained, the available generators are ranked in order of

their marginal costs from least to most costly. The marginal cost of the last generator needed to meet demand is

the relevant marginal cost in the Lerner comparison.95

In actuality the transmission grid is at times congested—power cannot be delivered as desired. PJM

again provides an example, as shown in Table 24. When

the system is congested, generators are recruited “out of

merit order” to stay within security limits (see Chapter 2

for a discussion of security limits). A congested system

segments into submarkets, all operating simultaneously. Sorting out which generator’s marginal costs to

pair with observed locational prices requires both an

electrical model and information on the amount of

demand and where it is located.

Areas that routinely find themselves in high-priced

submarkets are called “load pockets.” Because these

areas have limited recourse to outside suppliers, generators within load pockets are well placed to increase price

substantially above marginal cost.

50 Energy Information Administration / Electricity Transmission Data

  

   



 

 

 



 















2 4 6 8 10 12 14 16 18 20 22 24

Hour of Day

0

10

20

30

40

50

60

70 Dollars per Megawatthour

Figure 9. Average PJM Hourly Wholesale Price on

July 16, 2002

Source: Source: Data from web site www.pjm.com; markets,

energy, real-time, monthly real-time LMP, file 200207-rt.csv, loadweighted average prices.

Table 24. PJM Congested Hours (Real Time)

in 2002

Month Hours Congested

January . . . . . . . . . . . . . . . . . . 245

February . . . . . . . . . . . . . . . . . 79

March . . . . . . . . . . . . . . . . . . . 120

April . . . . . . . . . . . . . . . . . . . . . 263

May . . . . . . . . . . . . . . . . . . . . . 596

June. . . . . . . . . . . . . . . . . . . . . 664

July . . . . . . . . . . . . . . . . . . . . . 505

August . . . . . . . . . . . . . . . . . . . 540

September. . . . . . . . . . . . . . . . 595

October . . . . . . . . . . . . . . . . . . 540

November . . . . . . . . . . . . . . . . 533

December . . . . . . . . . . . . . . . . 550

Source: Source: PJM Interconnection, State of the Market Report

2002, Figure A-15, p. 165.

93A. Lerner, “The Concept of Monopoly and the Measurement of Economic Power,” Review of Economic Studies, Vol. 11 (1934), pp.

157-175.

94T.J. Brennan, “Mismeasuring Electricity Market Power,” Regulation (Spring 2003), pp. 60-65.

95It can happen that market demand is met at exactly the maximum capacity of the most expensive generator. In that case a competitive

price is consistent with any marginal cost between that of the last generator recruited and the generator required to meet any small additional demand. See S. Stoft, Power System Economics (New York, NY: John Wiley/IEEE Press, 2002), for a detailed discussion of these issues.

For the Lerner test to provide the correct answer, all generators able and economic to run at the time the comparison is made must be available for dispatch. If low-cost generators were withheld from the market, price would equal marginal cost, but market prices would be above

the competitive level.
Withholding and Manipulation of

Transmission Markets

Concentration ratios and Lerner indices shed little light

on how market participants can sustain artificially high

prices. They do not account for the kinds of capacity

withholding and grid manipulation that FERC has

observed in electricity markets.96 Withholding appears

to have been one way in which generators were able to

increase prices during the electricity crisis in California.

FERC sees withholding as sufficiently important that it

has developed a pivotal supplier test, which attempts to

identify generators whose absence would be enough to

result in significant price increases.97 The data needed to

calculate Lerner indices are adequate to identify pivotal

suppliers.

Enron showed how generators might take advantage of

market rules to manipulate transmission markets and

increase their profits. To the extent that gaming impacts

prices, the Lerner index may indicate that something is

amiss; however, it will not detect strategies that only

shift profits.

Joskow and Tirole make a more subtle point about the

ownership of financial transmission rights (congestion

revenue rights). Holders of these rights are paid the congestion revenues associated with the constrained lines

covered by their rights.98 Joskow and Tirole conclude:

The possession of financial rights by a producer in the

importing region or by a consumer in the exporting

region aggravates their market power, since financial

rights give them an extra incentive to curtail their output or demand to make the rights more valuable.99

Consequently, in those areas that use congestion rights,

data on their ownership could be important.

Limits on Market Power

Firms with market power do not have an unlimited ability to charge whatever they want to charge. New

entrants and the threat of new entrants into the market

have a constraining impact on market power in many

industries. To the extent that new competitors can enter

quickly at low cost, incumbent firms are dissuaded from

exercising market power. If competitors actually enter in

response to high prices, they will diminish the pricesetting power of incumbents.

Price increases lead to demand reductions in most

industries, and if the increases are pronounced, the

reductions in demand limit how much suppliers can

profitably charge. In the electricity industry, however,

there is presently a very limited degree of demand

response to price. Essentially all retail customers face

fixed prices, and consequently when demand

approaches the limits of supply, generators could—

absent regulatory intervention—raise prices without

fear of losing sales. Regulatory pressure is currently

more effective in disciplining prices than is demand

response.

The “natural” curbs on market power in the electricity

industry are limited, and the transmission grid provides

some generators with protection from competition. Both

considerations suggest that market prices may be above

competitive prices, at least when supplies are short.

Data on Wholesale Competition

Number of Firms and Concentration Ratios

Between FERC and EIA, the Federal Government has a

complete list of the larger generators, their capacity,

annual production, and ownership. Form EIA-860 is the

source for two periodic EIA reports, Inventory of Electric

Utility Power Plants in the United States and Inventory of

Nonutility Power Plants in the United States. The coverage

of small generators (especially cogenerators) is less complete, but given market boundaries, official data are adequate to identify the competitors and their capacities.

EIA also collects data on the output and heat rates of

individual generators, which allow calculation of market concentration ratios and the fuel portion of costs,

although those data are not publicly available.

Price Compared to Marginal Cost

These comparisons are a basic test of market competition. As explained above, they require data on market

prices and quantities, net trade flow, good estimates of

marginal cost and, when the grid is congested, an electrical model. ISOs have comprehensive data on market

prices, quantities, trade flows, offers to buy and sell, and

knowledge of operable units.100 They can also possess

the detailed knowledge necessary to estimate marginal

Energy Information Administration / Electricity Transmission Data 51

96See, for example, Federal Energy Regulatory Commission, “Final Report on Price Manipulation in Western Markets, Fact-Finding

Investigation of Potential Manipulation of Electric and Natural Gas Prices,” Staff Report, Docket No. PA02-2-000 (March 2003).

97The test amounts to removing hypothetically some or all of a generator’s capacity from the market supply. If that removal would cause

price to increase substantially above the competitive level, the generator is said to be pivotal.

98The congestion revenues are the difference in the prices at the receiving and sending locations, times the flow guaranteed by the right.

When the two prices are the same, there are no congestion revenues.

99P. Joskow and J. Tirole, “Transmission Rights and Market Power on Electric Power Networks,” The Rand Journal of Economics, Vol. 31,

No. 3 (Autumn 2000), p. 475.

100The market prices that ISOs report are occasionally “mitigated”: the ISO rejects the original market price and replaces it with the mitigated price when the ISO concludes that the former is exorbitant.
cost, placing them (or their market monitors) in a good

position to compute and interpret Lerner indices.101

PJM has released estimates of the Lerner index for its

system, reporting the markup over price.102 In addition

to having valid electrical models and comprehensive

data on generator availability, offers, production, and

demand volumes and locations, PJM had cost data on all

units whose construction started before July 9, 1996.103

PJM calculated the Lerner index for every 5-minute

interval and accounted for congestion. PJM has not,

however, released the underlying data and models necessary to replicate those results.

PJM reported two estimates of the average markup as a

percentage of price. The first, called the “adjusted

markup,” assumed that PJM’s marginal cost estimates

were precise. The resulting index averaged 11 percent

for 2002, with a maximum of 13 percent (in July) and a

minimum of 10 percent. The second assumed that the

marginal cost estimates did not incorporate all relevant

costs, and PJM increased the marginal cost estimates by

10 percent (presumably to cover such difficult-tomeasure items as variable operations and maintenance

costs). The result lowered the average markup to 2 percent in 2002, with a maximum of 4 percent in July and a

minimum of 1 percent.104 PJM interprets the results as

follows:

. . . the data on the price-cost markup are consistent with

the conclusion that the energy market was reasonably

competitive in 2002 although the evidence is not

dispositive.105

Official data for areas outside ISOs are far less precise.

On Forms EIA-860 and EIA-423, EIA collects (but does

not publicly release) generator fuel costs, heat rates, and

similar information for estimating marginal cost. Fuel

costs are reported monthly and heat rates tend to be

long-term averages. Because a generator’s heat rate varies significantly depending on utilization and operating

regime (startup, shutdown, etc.), marginal cost estimates based on those data are likely to be imprecise

approximations of hourly marginal costs. Hourly data

on generation from fossil-fueled and hydroelectric facilities (pumped storage) are not available from EIA.

In comparing price to the marginal cost of serving the

wholesale market, it is necessary to know which

generators were available at the time the wholesale price

comparisons were made. The U.S. Environmental Protection Agency (EPA), through its Continuous Emissions Monitoring System (CEMS), records hourly

emissions, and sometimes hourly output, from fossil-fueled generators.106 The absence of emissions is an

indicator that a particular plant is not operating.

Outside ISOs, there are no official hourly market prices.

There are commercially available prices at a few “hubs,”

but it is unclear how closely those prices approximate

market prices. If market data showed multiple prices, it

would be necessary to have an accurate electrical model

to determine whether the differences reflected congestion or something else. As mentioned previously, the

Federal Government does not maintain such models.

Also, outside the ISOs, official data do not support firm

conclusions about the presence or absence of competitive wholesale markets.

Entry

Chapter 3 showed that the Federal Government has

comprehensive data on the connection of larger generators to the electricity transmission grid. A large number

of independent generators have entered the market

since 1999, and official data reflect little about the costs

and time lags associated with entry. Further, official

data on access are not archived in a form that allows statistical analysis of access availability and quality of

service.

Demand-Price Response

The Federal Government collects no data on the amount

of consumption that is metered for price response, nor

does it routinely collect data on consumer participation

and behavior in price-responsive demand programs.

ISOs periodically release information about their programs, which, to the extent that relevant data are

reported, indicates that demand response is minuscule.

The New England ISO, for example, reports on its web

site the number of customers signed up for each program and the megawatts (MW) available for response:

As of November 1, 2002, there were 248 customers

signed up for the load response program providing

195.615 MWs of possible load relief. There are 122.494

MWs in the Class 1 Program and 73.121 MWs in the

Class 2 Program.107

52 Energy Information Administration / Electricity Transmission Data

101Independent researchers have made similar calculations using price data from ISOs. See, for example, S. Borenstein, J. Bushnell, and

F. Wolak, Measuring Market Imperfections in California’s Restructured Wholesale Electricity Market, CSEM WP102 (University of California

Energy Institute, June 2002).

102Calculated as: (market price - marginal cost)/(market price).

103PJM Interconnection, 2002 State of the Market, p. 28, web site www.pjm.com/markets/market-monitor/reports.html.

104Ibid.

105Ibid., p. 5.

106EPA’s emphasis is on emissions. Some records show significant generation without any fuel input.

107See web site www.iso-ne.com/Load_Response/main.html January 22, 2003.
The total possible load relief is only 0.7 percent of New

England’s installed capacity in 2000.108

Similarly, PJM’s State of the Marketreport finds that, “The

maximum hourly reduction in load that resulted from

PJM programs was 1,833 MWh in 2002.”109 This compares with a maximum daily peak demand of 63,762

MW in 2002. Clearly, demand response is not a counterweight to market power at this time.

Filling the Information Gaps

Outside ISOs, the government does not have the data

necessary to monitor and evaluate the competitive status of wholesale electricity markets. Government can

subpoena data in response to clear behavioral evidence

of anticompetitive behavior or as part of a merger

approval, but the subpoena is not a reasonable means of

obtaining data for routine monitoring of the market.

If Federal regulators and antitrust officials are satisfied

with market share analyses, then the critical need is for

high-quality power flow models and associated data

described in Chapter 2. That information is required to

delineate market boundaries.

If Federal regulators and antitrust officials require

Lerner indices for non-ISO areas, significantly more data

than are currently available would be needed. Critical

data missing are high-frequency wholesale prices, generator output and availability, and demand net of power

inflows. High-frequency market-specific wholesale

price data would require new data collections.

Hourly generation data from fossil-fueled units would

be available if EPA required (rather than just encouraging) generators to report actual generation quantities

injected into the grid on the CEMS; however, CEMS does

not apply to generation from nuclear units, hydropower

(including pumped storage), wind, solar, and geothermal units. Hourly generation data for nuclear and Federal hydropower plants exist, but they are not readily

available. Utilities and independent power producers

have production data for the other sources; however,

neither EIA nor FERC currently collects them. NERC

maintains extensive data on generator availability.

Demand by control region is reported hourly on FERC

Form 714. As noted in Chapter 2, those data are not

disaggregated to individual buses, reporting is incomplete, and the data from different reporters are contradictory. Because hourly net power inflows are not

reported, net demand cannot be calculated.

By contrast, ISOs have all the data required to delineate

markets within their areas and to compute concentration ratios and Lerner indices.110 FERC has the power to

require that ISO data necessary to gauge competition be

made routinely available to government policymakers

and analysts, but to date FERC has not issued such a

requirement.

Information on demand response to prices could be

obtained by adding a new schedule to Form EIA-861.

The required information would include potential

megawatts metered to record hourly (or higher frequency) consumption and megawatthours charged by

time of consumption.

Energy Information Administration / Electricity Transmission Data 53

108Energy Information Administration, Electric Power Annual 2000, DOE/EIA-0348(2000) (Washington, DC, August 2001), Volume II,

Table 3.

109PJM Interconnection, 2002 State of the Market, p. 37, web site www.pjm.com/markets/market-monitor/reports.html.

110If the statistics indicate noncompetitive pricing, special-purpose data collections can be employed to determine how (withholding,

manipulation of transmission markets, etc.) market participants are thwarting efficient pricing.

Appendix A

Federal Data Collections

FERC Form 1, “Annual Report of Major Electric Utilities, Licensees and Others,” is filed with the FERC and

can provide DOE/EIA with a comprehensive listing of

transmission data for investor-owned utilities. Data

from this form include line location, voltage rating,

structure type, conductor information, number of circuits, and land and construction costs. This form also

delineates whether the data are related to either old or

new transmission lines. The FERC Form 1 is one of the

most useful data sources for investor-owned utilities

with critical information related to transmission line

identification, ownership, physical/electrical characteristics, and cost.

FERC Form 714, “Annual Electric Control and

Planning Area Report,” is filed annually by electric utilities or groups of electric utilities that operate a control

area with annual peak demand greater than 200 megawatts. Information related to transmission reported on

this form includes adjacent control area names, control

area interconnection line/bus names, control area

scheduled and actual interchanges, and corresponding

line/bus voltage.

FERC Form 715, “Annual Transmission Planning and

Evaluation Report,” is filed annually by any transmitting utility that operates network (not radial) transmission facilities at or above 100 kV. In the case of joint

ownership, only the operator of the facilities must complete the FERC Form 715. FERC requires each transmitting utility to submit in electronic form its base case

power flow data if it does not participate in the development and use of regional power flow data. A respondent

that participates in the development and use of regional

power flow studies must either submit the regional base

case power flow data or designate the regional organization to submit such data. Also included in the submittal

are transmission system maps and one-line diagrams, a

detailed description of the transmission planning reliability criteria used to evaluate system performance,

and a detailed evaluation of the respondent’s anticipated system performance as measured against its

stated reliability criteria, using its stated assessment

practices.

Form EIA-411, “Coordinated Bulk Power Supply Program Report,” is intended to provide DOE/EIA with an

industry-wide source of information regarding regional

supply and demand projections for a 5-year advance

period. The utilities and other electricity suppliers submit their Form EIA-411 information to their respective

NERC regional councils by April 1 of each year. NERC

collects the data from the regional councils and then provides the data to DOE/EIA. The data reported to

DOE/EIA in this form consist of a comprehensive list of

supply and demand figures for each NERC regional

council. Also included in the Form EIA-411 are transmission line maps, proposed transmission line data (including location, line length, expected service date, kV

rating, and ownership) and load flow studies. Finally,

the Form EIA-411 provides information on capacity

sales and purchases across regions.

Form EIA-412, “Annual Electric Industry Financial

Report,” is filed annually by municipal and Federal utilities and includes information similar to the FERC Form

1. Data from the Form EIA-412 include line location,

voltage rating, structure type, conductor information,

number of circuits, and land and construction costs. This

form also delineates whether the data are related to

either old or new transmission lines. The form contains

very useful data from municipal utilities with critical

information related to transmission line identification,

ownership, and physical/electrical characteristics.

Additionally, the form initiated collection of transmission data from cooperatives that own generation, beginning with the 2001 annual data.

Form EIA-417, “Emergency Incident and Disturbance

Report,” is filed at each occurrence of a loss of transmission ability by those electric utilities that operate a Control Area, and/or Reliability Coordinators, or other

electric utility, as appropriate. The type, cause, and

extent of the emergency are reported, as well as the

response and the eventual resolution of the emergency.

Most of the types of emergencies reported on this form

occur on local distribution systems rather than on transmission systems.

Form EIA-860, “Annual Electric Generator Report,”

collects data on the status of existing U.S. electric generating plants with a nameplate rating of 1 megawatt or

greater, and those plants scheduled for initial commercial operation within 5 years of the filing of the form.

Data are collected at the generator level, and include fuel

source. Respondents include both those in the electricity

generation industry and those in other industries (such

as manufacturing) that also generate electricity.

Form EIA-861, “Annual Electric Power Industry

Report,” reports on the status of electric power industry

participants involved in the generation, transmission,

and distribution of electric energy in the United States,

its territories, and Puerto Rico. Electric power industry

Energy Information Administration / Electricity Transmission Data 55
participants include electric utilities, wholesale power

marketers (registered with the FERC), energy service

providers (registered with the States), and electric

power producers. Data collected include information on

owned or leased transmission lines, purchases (sales) of

transmission services on other electrical systems, wholesale power marketing, retail power marketing, and

demand-side management (DSM) programs.

Form FE-781R collects electrical import/export data

from entities authorized to export electric energy, and

those authorized to construct, connect, operate or maintain facilities for the transmission of electric energy at an

international boundary as required by 10 CFR 205.308

and 205.325. Actual imports and exports of electricity

are reported in detail by month. Export authorization

holders primarily report quarterly, while Presidential

Permit holders report annually. DOE uses these data to

track electricity being imported into the United States.

RUS Form 7, “Financial and Statistical Report for Electrical Distribution Borrowers,” is filed annually by current RUS borrowers that do not own generation. Data

from this form includes miles of transmission lines and

transmission operating and maintenance expenses. The

information included in the RUS Form 7 is somewhat

limited in detail and scope and does not provide as

much critical data as the preceding non-RUS forms.

RUS Form 12, “Financial and Statistical Report for

Power Supply Borrowers and Electric Distribution

Borrowers with Generating Facilities,” is filed annually

by current RUS borrowers that own generation. Data

from this form includes miles of transmission lines by

voltage, limited substation information, and transmission operating and maintenance expenses. The information included in the RUS Form 12 is also somewhat

limited in detail and scope and does not provide as

much critical data as the preceding non-RUS forms.

56 Energy Information Administration / Electricity Transmission Data
Acronyms

DOE U.S. Department of Energy

ECAR East Central Area Reliability Coordination Agreement

EIA Energy Information Administration

ERCOT Electric Reliability Council of Texas

FERC Federal Energy Regulatory Commission

FRCC Florida Reliability Coordinating Council

GW, GWh Gigawatt, Gigawatthour

IPP Independent power producer

kW, kWh Kilowatt, Kilowatthour

MAAC Mid-Atlantic Area Council

MAIN Mid-America Interconnected Network

MAPP Mid-Continent Area Power Pool

MECS Michigan Electrical Coordinated Systems

MW, MWh Megawatt, Megawatthour

NERC North American Electric Reliability Council

NPCC Northeast Power Coordinating Council

OASIS Open Access Same Time Information Service

PJM PJM Interconnection

RTO Regional Transmission Organization

SERC Southeast Electric Reliability Council

SPP Southwest Power Pool

TVA Tennessee Valley Authority

WECC Western Electricity Coordinating Council

Energy Information Administration / Electricity Transmission Data 57

Electricity Glossary

Alternating Current (AC): An electric current that

reverses its direction at regularly recurring intervals.

ACE: Area Control Error in MW. A negative value indicates a condition of under-generation relative to system

load and imports, and a positive value denotes

over-generation.

Active Power: See “Real Power.”

Adequacy: The ability of the electric system to supply

the aggregate electrical demand and energy requirements of customers at all times, taking into account

scheduled and reasonably expected unscheduled outages of system elements.

AGC: Automatic Generation Control is a computation

based on measured frequency and computed economic

dispatch. Generation equipment under AGC automatically responds to signals from an EMS computer in real

time to adjust power output in response to a change in

system frequency, tie-line loading, or to a prescribed

relation between these quantities. Generator output is

adjusted so as to maintain a target system frequency

(usually 60 Hz) and any scheduled MW interchange

with other areas.

Apparent Power: The product of voltage and current

phasors. It comprises both active and reactive power,

usually expressed in kilovoltamperes (kVA) or

megavoltamperes (MVA).

Blackstart Capability: The ability of a generating unit or

station to go from a shutdown condition to an operating

condition and start delivering power without assistance

from the bulk electric system.

Bulk Electric System: A term commonly applied to the

portion of an electric utility system that encompasses the

electrical generation resources and bulk transmission

system.

Bulk Transmission: A functional or voltage classification relating to the higher voltage portion of the transmission system, specifically, lines at or above a voltage

level of 115 kV.

Bus: An electrical conductor that serves as a common

connection for two or more electrical circuits.

Capacitor Bank: A capacitor is an electrical device that

provides reactive power to the system and is often used

to compensate for reactive load and help support system

voltage. A bank is a collection of one or more capacitors

at a single location.

Capacity: See “Generator Capacity” and “Generator

Nameplate Capacity (Installed).”

Cascading: The uncontrolled successive loss of system

elements triggered by an incident. Cascading results in

widespread service interruption, which cannot be

restrained from sequentially spreading beyond an area

predetermined by appropriate studies.

Circuit: A conductor or a system of conductors through

which electric current flows.

Circuit Breaker: A switching device connected to the

end of a transmission line capable of opening or closing

the circuit in response to a command, usually from a

relay.

Control Area: An electric power system or combination

of electric power systems to which a common automatic

control scheme is applied in order to: (1) match, at all

times, the power output of the generators within the

electric power system(s) and capacity and energy purchased from entities outside the electric power system(s), with the load in the electric power system(s); (2)

maintain, within the limits of Good Utility Practice,

scheduled interchange with other Control Areas; (3)

maintain the frequency of the electric power system(s)

within reasonable limits in accordance with Good Utility Practice; and (4) provide sufficient generating capacity to maintain operating reserves in accordance with

Good Utility Practice.

Contingency: The unexpected failure or outage of a system component, such as a generator, transmission line,

circuit breaker, switch, or other electrical element. A

contingency also may include multiple components,

which are related by situations leading to simultaneous

component outages.

Control Area Operator: An individual or organization

responsible for controlling generation to maintain interchange schedule with other control areas and contributing to the frequency regulation of the interconnection.

The control area is an electric system that is bounded by

interconnection metering and telemetry.

Current (Electric): A flow of electrons in an electrical

conductor. The strength or rate of movement of the electricity is measured in amperes.

Curtailability: The right of a transmission provider to

interrupt all or part of a transmission service due to constraints that reduce the capability of the transmission

network to provide that transmission service. Transmission service is to be curtailed only in cases where system

reliability is threatened or emergency conditions exist.

Demand: The rate at which electric energy is delivered

to consumers or by a system or part of a system, generally expressed in kilowatts or megawatts, at a given

Energy Information Administration / Electricity Transmission Data 59
instant or averaged over any designated interval of time.

Also see “Load.”

DC: Direct current; current that is steady and does not

change sinusoidally with time (see “AC”).

Dispatch Operator: Control of an integrated electric system involving operations such as assignment of levels of

output to specific generating stations and other sources

of supply; control of transmission lines, substations, and

equipment; operation of principal interties and switching; and scheduling of energy transactions.

Distribution: The delivery of energy to retail customers.

Distribution Network: The portion of an electric system

that is dedicated to delivering electric energy to an end

user, at or below 69 kV. The distribution network consists primarily of low-voltage lines and transformers

that “transport” electricity from the bulk power system

to retail customers.

Disturbance: An unplanned event that produces an

abnormal system condition.

Electrical Energy: The generation or use of electric

power by a device over a period of time, expressed in

kilowatthours (kWh), megawatthours (MWh), or

gigawatthours (GWh).

Electric Utility: A corporation, person, agency, authority, or other legal entity or instrumentality aligned with

distribution facilities for delivery of electric energy for

use primarily by the public. Included are investor-owned electric utilities, municipal and State utilities,

Federal electric utilities, and rural electric cooperatives.

A few entities that are tariff based and corporately

aligned with companies that own distribution facilities

are also included. Note: Due to the issuance of FERC

Order 888 that required traditional electric utilities to

functionally unbundle their generation, transmission,

and distribution operations, “electric utility” currently

has inconsistent interpretations from State to State.

Element: Any electric device with terminals that may be

connected to other electric devices, such as a generator,

transformer, circuit, circuit breaker, or bus section.

Emergency: The failure of an electric power system to

generate or deliver electric power as normally intended,

resulting in the cutoff or curtailment of service.

Emergency Voltage Limits: The operating voltage

range on the interconnected systems that is acceptable

for the time, sufficient for system adjustments to be

made following a facility outage or system disturbance.

EMS: An energy management system is a computer control system used by electric utility dispatchers to monitor the real time performance of various elements of an

electric system and to control generation and transmission facilities.

Energy Emergency: A condition when a system or

power pool does not have adequate energy resources

(including water for hydro units) to supply its customers’ expected energy requirements.

Fault: A fault usually means a short circuit, but more

generally it refers to some abnormal system condition.

Faults are often random events.

Federal Energy Regulatory Commission (FERC): The

Federal agency with jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas pricing, oil pipeline rates, and gas

pipeline certification. FERC is an independent regulatory agency within the Department of Energy and is the

successor to the Federal Power Commission.

Flashover: A plasma arc initiated by some event such as

lightning. Its effect is a short circuit on the network.

Flowgate: A single or group of transmission elements

intended to model MW flow impact relating to transmission limitations and transmission service usage.

Forced Outage: The shutdown of a generating unit,

transmission line, or other facility for emergency reasons or a condition in which the generating equipment is

unavailable for load due to unanticipated breakdown.

Frequency: The number of complete alternations or

cycles per second of an alternating current, measured in

Hertz. The standard frequency in the United States is 60

Hz. In some other countries the standard is 50 Hz.

Frequency Deviation or Error: A departure from scheduled frequency; the difference between actual system

frequency and the scheduled system frequency.

Frequency Regulation: The ability of a Control Area to

assist the interconnected system in maintaining scheduled frequency. This assistance can include both turbine

governor response and automatic generation control.

Frequency Swings: Constant changes in frequency from

its nominal or steady-state value.

Generation (Electricity): The process of producing electrical energy from other forms of energy; also, the

amount of electric energy produced, usually expressed

in kilowatt hours (kWh) or megawatt hours (MWh).

Generator: Generally, an electromechanical device used

to convert mechanical power to electrical power.

Generator Capacity: The maximum output, commonly

expressed in megawatts (MW), that generating equipment can supply to system load, adjusted for ambient

conditions.

Generator Nameplate Capacity (Installed): The maximum rated output of a generator, prime mover, or other

electric power production equipment under specific

conditions designated by the manufacturer. Installed

60 Energy Information Administration / Electricity Transmission Data
generator nameplate capacity is commonly expressed in

megawatts (MW) and is usually indicated on a nameplate physically attached to the generator.

Grid: The layout of an electrical distribution system.

Grid Protection Scheme: Protection equipment for an

electric power system, consisting of circuit breakers, certain equipment for measuring electrical quantities (e.g.,

current and voltage sensors) and devices called relays.

Each relay is designed to protect the piece of equipment

it has been assigned from damage. The basic philosophy

in protection system design is that any equipment that is

threatened with damage by a sustained fault is to be

automatically taken out of service.

Ground: A conducting connection between an electrical

circuit or device and the earth. A ground may be intentional, as in the case of a safety ground, or accidental,

which may result in high overcurrents.

Imbalance: A condition where the generation and interchange schedules do not match demand.

Impedance: The opposition to power flow in an AC circuit. Also, any device that introduces such opposition in

the form of resistance, reactance, or both. The impedance of a circuit or device is measured as the ratio of voltage to current, where a sinusoidal voltage and current of

the same frequency are used for the measurement; it is

measured in ohms.

Independent System Operator (ISO): An independent,

Federally regulated entity established to coordinate

regional transmission in a non-discriminatory manner

and ensure the safety and reliability of the electric

system.

Interchange: Electric power or energy that flows across

tie-lines from one entity to another, whether scheduled

or inadvertent.

Interconnected System: A system consisting of two or

more individual electric systems that normally operate

in synchronism and have connecting tie lines.

Interconnection: Two or more electric systems having a

common transmission line that permits a flow of energy

between them. The physical connection of the electric

power transmission facilities allows for the sale or

exchange of energy.

Interface: The specific set of transmission elements

between two areas or between two areas comprising one

or more electrical systems.

ISAC: Information Sharing and Analysis Centers

(ISACs) are designed by the private sector and serve as a

mechanism for gathering, analyzing, appropriately sanitizing and disseminating private sector information.

These centers could also gather, analyze, and disseminate information from Government for further distribution to the private sector. ISACs also are expected to

share important information about vulnerabilities,

threats, intrusions, and anomalies, but do not interfere

with direct information exchanges between companies

and the Government.

Island: A portion of a power system or several power

systems that is electrically separated from the interconnection due to the disconnection of transmission system

elements.

Kilovar (kVAr): Unit of alternating current reactive

power equal to 1,000 VArs.

Kilovolt (kV): Unit of electrical potential equal to 1,000

Volts.

Kilovolt-Amperes (kVA): A unit of apparent power,

equal to 1,000 volt-amperes; the mathematical product

of the volts and amperes in an electrical circuit.

Kilowatthour (kWh): A measure of electricity defined

as a unit of work or energy, measured as 1 kilowatt

(1,000 watts) of power expended for 1 hour. One kWh is

equivalent to 3,412 Btu.

Line Trip: Refers to the automatic opening of the conducting path provided by a transmission line by the circuit breakers. These openings or “trips” are to protect

the transmission line during faulted conditions.

Load (Electric): The amount of electric power delivered

or required at any specific point or points on a system.

The requirement originates at the energy-consuming

equipment of the consumers. See “Demand.”

Load Shedding: Intentional action by a utility that

results in the reduction of more than 100 megawatts

(MW) of firm customer load for reasons of maintaining

the continuity of service of the reporting entity's bulk

electric power supply system. The routine use of load

control equipment that reduces firm customer load is

not considered to be a reportable action.

Lockout: A state of a transmission line following breaker

operations where the condition detected by the protective relaying was not eliminated by temporarily opening

and reclosing the line, possibly several times. In this

state, the circuit breakers cannot generally be reclosed

without resetting a lockout device.

Market Participant: An entity participating in the

energy marketplace by buying/selling transmission

rights, energy, or ancillary services into, out of, or

through an ISO-controlled grid.

Megawatthour (MWh): One million watthours.

Metered Value: A measured electrical quantity that may

be observed through telemetering, supervisory control

and data acquisition (SCADA), or other means.

Metering: The methods of applying devices that measure and register the amount and direction of electrical

quantities with respect to time.

Energy Information Administration / Electricity Transmission Data 61
NERC Interregional Security Network (ISN): A communications network used to exchange electric system

operating parameters in near real time among those

responsible for reliable operations of the electric system.

The ISN provides timely and accurate data and information exchange among reliability coordinators and other

system operators. The ISN, which operates over the

frame relay NERCnet system, is a private Intranet that is

capable of handling additional applications between

participants.

Normal (Precontingency) Operating Procedures: Operating procedures that are normally invoked by the system operator to alleviate potential facility overloads or

other potential system problems in anticipation of a

contingency.

Normal Voltage Limits: The operating voltage range on

the interconnected systems that is acceptable on a sustained basis.

North American Electric Reliability Council (NERC):

A council formed in 1968 by the electric utility industry

to promote the reliability and adequacy of bulk power

supply in the electric utility systems of North America.

NERC consists of regional reliability councils and

encompasses essentially all the power regions of the

contiguous United States, Canada, and Mexico.

OASIS: Open Access Same Time Information Service

(OASIS), developed by the Electric Power Research

Institute, is designed to facilitate open access by providing users with access to information on transmission services and availability, plus facilities for transactions.

Operating Criteria: The fundamental principles of reliable interconnected systems operation, adopted by

NERC.

Operating Guides: Operating practices that a Control

Area or systems functioning as part of a Control Area

may wish to consider. The application of Guides is

optional and may vary among Control Areas to accommodate local conditions and individual system

requirements.

Operating Policies: The doctrine developed for interconnected systems operation. This doctrine consists of

Criteria, Standards, Requirements, Guides, and instructions, which apply to all Control Areas.

Operating Procedures: A set of policies, practices, or

system adjustments that may be automatically or manually implemented by the system operator within a specified time frame to maintain the operational integrity of

the interconnected electric systems.

Operating Requirements: Obligations of a Control Area

and systems functioning as part of a Control Area.

Operating Security Limit: The value of a system operating parameter (e.g. total power transfer across an interface) that satisfies the most limiting of prescribed preand post-contingency operating criteria as determined

by equipment loading capability and acceptable stability and voltage conditions. It is the operating limit to be

observed so that the transmission system will remain

reliable even if the worst contingency occurs.

Operating Standards: The obligations of a Control Area

and systems functioning as part of a Control Area that

are measurable. An Operating Standard may specify

monitoring and surveys for compliance.

Outage: The period during which a generating unit,

transmission line, or other facility is out of service.

Planning Guides: Good planning practices and considerations that Regions, subregions, power pools, or individual systems should follow. The application of

Planning Guides may vary to match local conditions and

individual system requirements.

Planning Policies: The framework for the reliability of

interconnected bulk electric supply in terms of responsibilities for the development of and conformance to

NERC Planning Principles and Guides and Regional

planning criteria or guides, and NERC and Regional

issues resolution processes. NERC Planning Procedures,

Principles, and Guides emanate from the Planning

Policies.

Planning Principles: The fundamental characteristics of

reliable interconnected bulk electric systems and the tenets for planning them.

Planning Procedures: An explanation of how

the Planning Policies are addressed and implemented

by the NERC Engineering Committee, its subgroups,

and the Regional Councils to achieve bulk electric system reliability.

Post-contingency Operating Procedures: Operating

procedures that may be invoked by the system operator

to mitigate or alleviate system problems after a contingency has occurred.

Protective Relay: A device designed to detect abnormal

system conditions, such as electrical shorts on the electric system or within generating plants, and initiate the

operation of circuit breakers or other control equipment.

Power/Phase Angle: The angular relationship between

an AC (sinusoidal) voltage across a circuit element and

the AC (sinusoidal) current through it. The real power

that can flow is related to this angle.

Power: See “Real Power.”

Power Flow: See “Current.”

Rate: The authorized charges per unite or level of consumption for a specified time period for any of the

classes of utility services provided to a customer.

Rating: A manufacturer’s guaranteed performance of a

machine, transmission line, or other electrical apparatus,

62 Energy Information Administration / Electricity Transmission Data
based on design features and test data. The rating will

specify such limits as load, voltage, temperature, and

frequency. The rating is generally printed on a nameplate attached to equipment and is commonly referred

to as the nameplate rating or nameplate capacity.

Reactive Power: The electrical power that oscillates

between the magnetic field of an inductor and the electrical field of a capacitor. Reactive power is never converted to nonelectrical power. It is calculated as the

square root of the difference between the square of the

kilovolt-amperes and the square of the kilowatts and is

expressed as reactive volt-amperes.

Readiness: The extent to which an organizational entity

is prepared to meet the functional requirements set by

NERC or its regional council for entities of that type or

class.

Real Power: Also known as “active power.” The rate at

which work is performed or that energy is transferred,

usually expressed in kilowatts (kW) or megawatts

(MW). The terms “active power” or “real power” are

often used in place of the term power alone to differentiate it from reactive power.

Real-Time Operations: The instantaneous operations of

a power system as opposed to those operations that are

simulated.

Regional Reliability Council: One of ten Electric Reliability Councils that form the North American Electric

Reliability Council (NERC).

Regional Transmission Operator (RTO): An organization that is independent from all generation and power

marketing interests and has exclusive responsibility for

electric transmission grid operations, short-term electric

reliability, and transmission services within a multiState region. To achieve those objectives, the RTO

manages transmission facilities owned by different companies and encompassing one, large, contiguous geographic area.

Regulation: The governmental function of controlling

or directing economic entities through the process of

rulemaking and adjudication.

Regulations: Rules issued by regulatory authorities to

implement laws passed by legislative bodies.

Relay: A device that controls the opening and subsequent reclosing of circuit breakers. Relays take measurements from local current and voltage transformers, and

from communication channels connected to the remote

end of the lines. A relay output trip signal is sent to circuit breakers when needed.

Relay Setting: The parameters that determine when a

protective relay will initiate operation of circuit breakers

or other control equipment.

Reliability Coordinator: An individual or organization

responsible for the safe and reliable operation of the

interconnected transmission system for their defined

area, in accordance with NERC reliability standards,

regional criteria, and subregional criteria and practices.

This entity facilitates the sharing of data and information about the status of the Control Areas for which it is

responsible, establishes a security policy for these Control Areas and their interconnections, and coordinates

emergency operating procedures that rely on common

operating terminology, criteria, and standards.

Resistance: The characteristic of materials to restrict the

flow of current in an electric circuit. Resistance is inherent in any electric wire, including those used for the

transmission of electric power. Resistance in the wire is

responsible for heating the wire as current flows

through it and the subsequent power loss due to that

heating.

Restoration: The process of returning generators and

transmission system elements and restoring load following an outage on the electric system.

Right-of-Way (ROW) Maintenance: Activities by utilities to maintain electrical clearances along transmission

or distribution lines.

Safe Limits: System limits on quantities such as voltage

or power flows such that if the system is operated within

these limits it is secure and reliable.

SCADA: Supervisory Control and Data Acquisition system; a system of remote control and telemetry used to

monitor and control the electric system.

Schedule: A statement of the pricing format of electricity and the terms and conditions governing its

applications.

Scheduling Coordinators: Entities certified by the Federal Energy Regulatory Commission (FERC) that act on

behalf of generators, supply aggregators (wholesale

marketers), retailers, and customers to schedule the distribution of electricity.

Seams: The boundaries between adjacent electricity-related organizations. Differences in regulatory

requirements or operating practices may create “seams

problems.”

Security: The ability of the electric system to withstand

sudden disturbances such as electric short circuits or

unanticipated loss of system elements.

Security Coordinator: An individual or organization

that provides the security assessment and emergency

operations coordination for a group of Control Areas.

Short Circuit: An electric current taking a shorter or different path than intended.

Energy Information Administration / Electricity Transmission Data 63
Shunt Capacitor Bank: Shunt capacitors are capacitors

connected from the power system to an electrical

ground. They are used to supply kilovars (reactive

power) to the system at the point where they are connected. A shunt capacitor bank is a group of shunt

capacitors.

Single Contingency: The sudden, unexpected failure or

outage of a system facility(s) or element(s) (generating

unit, transmission line, transformer, etc.). Elements

removed from service as part of the operation of a remedial action scheme are considered part of a single

contingency.

Special Protection System: An automatic protection

system designed to detect abnormal or predetermined

system conditions, and take corrective actions other

than and/or in addition to the isolation of faulted

components.

Stability: The property of a system or element by virture

of which its output will ultimately attain a steady state.

The amount of power that can be transferred from one

machine to another following a disturbance. The stability of a power system is its ability to develop restoring

forces equal to or greater than the disturbing forces so as

to maintain a state of equilibrium.

Stability Limit: The maximum power flow possible

through a particular point in the system while maintaining stability in the entire system or the part of the system

to which the stability limit refers.

State Estimator: Computer software that takes redundant measurements of quantities related to system state

as input and provides an estimate of the system state

(bus voltage phasors). It is used to confirm that the monitored electric power system is operating in a secure

state by simulating the system both at the present time

and one step ahead, for a particular network topology

and loading condition. With the use of a state estimator

and its associated contingency analysis software, system

operators can review each critical contingency to determine whether each possible future state is within reliability limits.

Station (Electric): A plant containing prime movers,

electric generators, and auxiliary equipment for converting mechanical, chemical, and/or nuclear energy into

electric energy.

Storage: Energy transferred form one entity to another

entity that has the ability to conserve the energy (i.e.,

stored as water in a reservoir, coal in a pile, etc.) with the

intent that the energy will be returned at a time when

such energy is more useable to the original supplying

entity.

Substation: Facility equipment that switches, changes,

or regulates electric voltage.

Subtransmission: A set of transmission lines of voltages

between transmission voltages and distribution voltages. Generally, lines in the voltage range of 69 kV to 138

kV. Note: In this report, subtransmission focuses on

lines at voltage levels between 69 kV and 115 kV.

Supervisory Control and Data Acquisition (SCADA):

See SCADA.

Surge: A transient variation of current, voltage, or

power flow in an electric circuit or across an electric

system.

Surge Impedance Loading: The maximum amount of

real power that can flow down a lossless transmission

line such that the line does not require any VArs to support the flow.

Switching Station: Facility equipment used to tie

together two or more electric circuits through switches.

The switches are selectively arranged to permit a circuit

to be disconnected, or to change the electric connection

between the circuits.

Synchronize: The process of connecting two previously

separated alternating current apparatuses after matching frequency, voltage, phase angles, etc. (e.g., paralleling a generator to the electric system).

System (Electric): Physically connected generation,

transmission, and distribution facilities operated as an

integrated unit under one central management or operating supervision.

System Operator: An individual at an electric system

control center whose responsibility it is to monitor and

control that electric system in real time.

System Reliability: A measure of an electric system’s

ability to deliver uninterrupted service at the proper

voltage and frequency.

Thermal Limit: The maximum amount of power a

transmission line can carry without suffering heatrelated deterioration of line equipment, particularly

conductors.

Tie-line: A transmission line connecting two or more

power systems.

Time Error: An accumulated time difference between

Control Area system time and the time standard. Time

error is caused by a deviation in Interconnection frequency from 60.0 Hertz.

Time Error Correction: An offset to the Interconnection’s scheduled frequency to correct for the time error

accumulated on electric clocks.

Transactions: Sales of bulk power via the transmission

grid.

Transfer Limit: The maximum amount of power that

can be transferred in a reliable manner from one area to

64 Energy Information Administration / Electricity Transmission Data
another over all transmission lines (or paths) between

those areas under specified system conditions.

Transformer: An electrical device for changing the voltage of alternating current.

Transient Stability: The ability of an electric system to

maintain synchronism between its parts when subjected

to a disturbance and to regain a state of equilibrium following that disturbance.

Transmission: An interconnected group of lines and

associated equipment for the movement or transfer of

electric energy between points of supply and points at

which it is transformed for delivery to customers or is

delivered to other electric systems.

Transmission Loading Relief (TLR): A procedure used

to manage congestion on the electric transmission

system.

Transmission Margin: The difference between the maximum power flow a transmission line can handle and

the amount that is currently flowing on the line.

Transmission Operator: NERC-certified party responsible for monitoring and assessing local reliability conditions, who operates the transmission facilities, and who

executes switching orders in support of the Reliability

Authority.

Transmission Overload: A state where a transmission

line has exceeded either a normal or emergency rating of

the electric conductor.

Transmission Owner (TO) or Transmission Provider:

Any utility that owns, operates, or controls facilities

used for the transmission of electric energy.

Trip: The opening of a circuit breaker or breakers on an

electric system, normally to electrically isolate a particular element of the system to prevent it from being damaged by fault current or other potentially damaging

conditions. See “Line Trip” for example.

Voltage: The difference in electrical potential between

any two conductors or between a conductor and

ground. It is a measure of the electric energy per electron

that electrons can acquire and/or give up as they move

between the two conductors.

Voltage Collapse (decay): An event that occurs when an

electric system does not have adequate reactive support

to maintain voltage stability. Voltage Collapse may

result in outage of system elements and may include

interruption in service to customers.

Voltage Control: The control of transmission voltage

through adjustments in generator reactive output and

transformer taps, and by switching capacitors and

inductors on the transmission and distribution systems.

Voltage Limits: A hard limit above or below which is an

undesirable operating condition. Normal limits are

between 95 and 105 percent of the nominal voltage at the

bus under discussion.

Voltage Reduction: Any intentional reduction of system

voltage by 3 percent or greater for reasons of maintaining the continuity of service of the bulk electric power

supply system.

Voltage Stability: The condition of an electric system in

which the sustained voltage level is controllable and

within predetermined limits.

Watthour (Wh): The electrical energy unit of measure

equal to one watt of power supplied to, or taken from, an

electric circuit steadily for one hour.

Energy Information Administration / Electricity Transmission Data 65